Communicatively Connecting a Control Workstation with Wellsite Equipment

ABSTRACT

An apparatus and method for communicatively connecting a control workstation with wellsite equipment. The apparatus may include a data communication hub communicatively connected with fluid control equipment of a well construction system for constructing a well at an oil/gas wellsite, and a control workstation communicatively connected with tubular handling and rotation equipment of the well construction system. The control workstation may be communicatively connected with the data communication hub and with the fluid control equipment via the data communication hub.

BACKGROUND OF THE DISCLOSURE

Wells are generally drilled into the ground or ocean bed to recover natural deposits of oil, gas, and other materials that are trapped in subterranean formations. Such wells are drilled into the subterranean formations at the wellsite utilizing a well construction system having various surface and subterranean wellsite equipment operating in a coordinated manner. The wellsite equipment may be grouped into various subsystems, wherein each subsystem performs a different operation controlled by a corresponding local and/or a remotely located controller. The subsystems may include a rig control system, a fluid control system, a managed pressure drilling control system, a gas monitoring system, a closed-circuit television system, a choke pressure control system, and a well pressure control system, among other examples.

The wellsite equipment may be monitored and controlled from a control center located at a wellsite surface. The control center may contain a plurality of control panels or stations, each operable to monitor and control corresponding wellsite equipment or equipment subsystem. Although the various equipment subsystems may operate in a coordinated manner, there is little or no communication between the subsystems or their control panels.

Because there is no communication between the various equipment subsystems or their control panels, the equipment subsystems operate in a standalone manner and interactions and coordination between the equipment subsystems are typically initiated by the wellsite operators. Accordingly, a typical wellsite control center may be manned by multiple human wellsite operators (e.g., drillers), each monitoring and controlling different wellsite equipment or equipment subsystem via a corresponding control panel. The lack of communication between the subsystems also does not permit diagnostics, condition monitoring, and/or integrated control to be performed from a driller's chair of a rig control workstation. When equipment maintenance is needed or an equipment malfunction occurs, no centralized warning mechanism exists. The wellsite operators may, thus, visually monitor the wellsite equipment to identify operational and safety events and manually implement processes to counteract such events via the corresponding control panels. Relying on multiple wellsite operators to visually monitor and manually control the wellsite equipment results in inefficient operation of the well construction system. Furthermore, lack of centralized troubleshooting and diagnostics increases operational downtime and limits wellsite safety.

SUMMARY OF THE DISCLOSURE

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.

The present disclosure introduces an apparatus including a data communication hub and a control workstation. The data communication hub is communicatively connected with fluid control equipment of a well construction system for constructing a well at an oil/gas wellsite. The control workstation is communicatively connected with the data communication hub and with tubular handling and rotation equipment of the well construction system. The control workstation is communicatively connected with the fluid control equipment via the data communication hub.

The present disclosure also introduces an apparatus including a control workstation for controlling a well construction system to construct a well at an oil/gas wellsite. The control workstation receives, from fluid control equipment of the well construction system, first information indicative of operational status of the fluid control equipment. The control workstation also receives, from tubular handling and rotation equipment of the well construction system, second information indicative of operational status of the tubular handling and rotation equipment. The apparatus also includes a data communication hub communicatively connected with the fluid control equipment via first multi-conductor cables each connected with a corresponding piece of the fluid control equipment. The data communication hub is communicatively connected with the control workstation via a second multi-conductor cable. The data communication hub receives first information from the fluid control equipment via the first multi-conductor cables, and transmits the first information to the control workstation via the second multi-conductor cable.

The present disclosure also introduces a method including operating a well construction system to construct a well at an oil/gas wellsite while generating first information indicative of operational status of fluid control equipment of the well construction system and generating second information indicative of operational status of tubular handling and rotation equipment of the well construction system. The method also includes operating a data communication hub to receive the first information and transmit the first information using a predetermined communication protocol. The method also includes operating a control workstation for controlling the well construction system to receive the first information from the data communication hub and receive the second information from the tubular handling and rotation equipment.

These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic side view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 3 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 4 is a perspective view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 5 is a perspective sectional view of the apparatus shown in FIG. 4 according to one or more aspects of the present disclosure.

FIG. 6 is a top view of a portion of an example implementation of the apparatus shown in FIG. 5 according to one or more aspects of the present disclosure.

FIGS. 7-9 are example implementations of software controls displayed by the apparatus shown in FIG. 6 according to one or more aspects of the present disclosure.

FIG. 10 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 11 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 12 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 13 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 14 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 15 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure describes many example implementations for different aspects introduced herein. Specific examples of components and arrangements are described below to simplify the present disclosure. These are merely examples, and are not intended to be limiting. In addition, the present disclosure may repeat reference numbers and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various implementations described herein. Moreover, the formation of a first feature over or on a second feature in the description that follows may include implementations in which the first and second features are formed in direct contact, and may also include implementations in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.

Systems and methods (e.g., processes, operations) according to one or more aspects of the present disclosure may be utilized or otherwise implemented in association with an automated well construction system at an oil and gas wellsite, such as for constructing a wellbore to obtain hydrocarbons (e.g., oil and/or gas) from a subterranean formation. However, one or more aspects of the present disclosure may be utilized or otherwise implemented in association with other automated systems in the oil and gas industry and other industries. For example, one or more aspects of the present disclosure may be implemented in association with wellsite systems for performing fracturing, cementing, acidizing, chemical injecting, and/or water jet cutting operations, among other examples. One or more aspects of the present disclosure may also be implemented in association with mining sites, building construction sites, and/or other work sites where automated machines or equipment are utilized.

FIG. 1 is a schematic view of at least a portion of an example implementation of a well construction system 100 according to one or more aspects of the present disclosure. The well construction system 100 represents an example environment in which one or more aspects of the present disclosure described below may be implemented. The well construction system 100 may be or comprise a drill rig and associated wellsite equipment. Although the well construction system 100 is depicted as an onshore implementation, the aspects described below are also applicable to offshore implementations.

The well construction system 100 is depicted in relation to a wellbore 102 formed by rotary and/or directional drilling from a wellsite surface 104 and extending into a subterranean formation 106. The well construction system 100 includes surface equipment 110 located at the wellsite surface 104 and a drill string 120 suspended within the wellbore 102. The surface equipment 110 may include a mast, a derrick, and/or another support structure 112 disposed over a rig floor 114. The drill string 120 may be suspended within the wellbore 102 from the support structure 112. The support structure 112 and the rig floor 114 are collectively supported over the wellbore 102 by legs and/or other support structures (not shown).

The drill string 120 may comprise a bottom-hole assembly (BHA) 124 and means 122 for conveying the BHA 124 within the wellbore 102. The conveyance means 122 may comprise a plurality of interconnected tubulars, such as drill pipe, heavy-weight drill pipe (HWDP), wired drill pipe (WDP), tough logging condition (TLC) pipe, and drill collars, among other examples. The conveyance means 122 may instead comprise coiled tubing for conveying the BHA 124 within the wellbore 102. A downhole end of the BHA 124 may include or be coupled to a drill bit 126. Rotation of the drill bit 126 and the weight of the drill string 120 collectively operate to form the wellbore 102. The drill bit 126 may be rotated from the wellsite surface 104 and/or via a downhole mud motor (not shown) connected with the drill bit 126. The BHA 124 may also include various downhole tools 180, 182, 184.

One or more of the downhole tools 180, 182, 184 may be or comprise an MWD or LWD tool comprising a sensor package 186 operable for the acquisition of measurement data pertaining to the BHA 124, the wellbore 102, and/or the formation 106. One or more of the downhole tools 180, 182, 184 and/or another portion of the BHA 124 may also comprise a telemetry device 187 operable for communication with the surface equipment 110, such as via mud-pulse telemetry. One or more of the downhole tools 180, 182, 184 and/or another portion of the BHA 124 may also comprise a downhole processing device 188 operable to receive, process, and/or store information received from the surface equipment 110, the sensor package 186, and/or other portions of the BHA 124. The processing device 188 may also store executable computer programs (e.g., program code instructions), including for implementing one or more aspects of the operations described herein.

The support structure 112 may support a driver, such as a top drive 116, operable to connect (perhaps indirectly) with an upper end of the drill string 120, and to impart rotary motion 117 and vertical motion 135 to the drill string 120, including the drill bit 126. However, another driver, such as a kelly and rotary table (neither shown), may be utilized instead of or in addition to the top drive 116 to impart the rotary motion 117 to the drill string 120. The top drive 116 and the connected drill string 120 may be suspended from the support structure 112 via a hoisting system or equipment, which may include a traveling block 113, a crown block 115, and a draw works 118 storing a support cable or line 123. The crown block 115 may be connected to or otherwise supported by the support structure 112, and the traveling block 113 may be coupled with the top drive 116. The draw works 118 may be mounted on or otherwise supported by the rig floor 114. The crown block 115 and traveling block 113 comprise pulleys or sheaves around which the support line 123 is reeved to operatively connect the crown block 115, the traveling block 113, and the draw works 118 (and perhaps an anchor). The draw works 118 may thus selectively impart tension to the support line 123 to lift and lower the top drive 116, resulting in the vertical motion 135. The draw works 118 may comprise a drum, a base, and a prime mover (e.g., an engine or motor) (not shown) operable to drive the drum to rotate and reel in the support line 123, causing the traveling block 113 and the top drive 116 to move upward. The draw works 118 may be operable to reel out the support line 123 via a controlled rotation of the drum, causing the traveling block 113 and the top drive 116 to move downward.

The top drive 116 may comprise a grabber, a swivel (neither shown), elevator links 127 terminating with an elevator 129, and a drive shaft 125 operatively connected with a prime mover (not shown), such as via a gear box or transmission (not shown). The drive shaft 125 may be selectively coupled with the upper end of the drill string 120 and the prime mover may be selectively operated to rotate the drive shaft 125 and the drill string 120 coupled with the drive shaft 125. Hence, during drilling operations, the top drive 116, in conjunction with operation of the draw works 118, may advance the drill string 120 into the formation 106 to form the wellbore 102. The elevator links 127 and the elevator 129 of the top drive 116 may handle tubulars (e.g., drill pipes, drill collars, casing joints, etc.) that are not mechanically coupled to the drive shaft 125. For example, when the drill string 120 is being tripped into or out of the wellbore 102, the elevator 129 may grasp the tubulars of the drill string 120 such that the tubulars may be raised and/or lowered via the hoisting equipment mechanically coupled to the top drive 116. The grabber may include a clamp that clamps onto a tubular when making up and/or breaking out a connection of a tubular with the drive shaft 125. The top drive 116 may have a guide system (not shown), such as rollers that track up and down a guide rail on the support structure 112. The guide system may aid in keeping the top drive 116 aligned with the wellbore 102, and in preventing the top drive 116 from rotating during drilling by transferring reactive torque to the support structure 112.

The well construction system 100 may further include a well control system or equipment for maintaining well pressure control. For example, the drill string 120 may be conveyed within the wellbore 102 through various blowout preventer (BOP) equipment disposed at the wellsite surface 104 on top of the wellbore 102 and perhaps below the rig floor 114. The BOP equipment may be operable to control pressure within the wellbore 102 via a series of pressure barriers (e.g., rams) between the wellbore 102 and the wellsite surface 104. The BOP equipment may include a BOP stack 130, an annular preventer 132, and/or a rotating control device (RCD) 138 mounted above the annular preventer 132. The BOP equipment 130, 132, 138 may be mounted on top of a wellhead 134. The well control system may further include a BOP control unit 137 (i.e., a BOP closing unit) operatively connected with the BOP equipment 130, 132, 138 and operable to actuate, drive, operate or otherwise control the BOP equipment 130, 132, 138. The BOP control unit 137 may be or comprise a hydraulic fluid power unit fluidly connected with the BOP equipment 130, 132, 138 and selectively operable to hydraulically drive various portions (e.g., rams, valves, seals) of the BOP equipment 130, 132, 138.

The well construction system 100 may further include a drilling fluid circulation system or equipment operable to circulate fluids between the surface equipment 110 and the drill bit 126 during drilling and other operations. For example, the drilling fluid circulation system may be operable to inject a drilling fluid from the wellsite surface 104 into the wellbore 102 via an internal fluid passage 121 extending longitudinally through the drill string 120. The drilling fluid circulation system may comprise a pit, a tank, and/or other fluid container 142 holding the drilling fluid (i.e., mud) 140, and a pump 144 operable to move the drilling fluid 140 from the container 142 into the fluid passage 121 of the drill string 120 via a fluid conduit 146 extending from the pump 144 to the top drive 116 and an internal passage extending through the top drive 116. The fluid conduit 146 may comprise one or more of a pump discharge line, a stand pipe, a rotary hose, and a gooseneck connected with a fluid inlet of the top drive 116. The pump 144 and the container 142 may be fluidly connected by a fluid conduit 148, such as a suction line.

During drilling operations, the drilling fluid may continue to flow downhole through the internal passage 121 of the drill string 120, as indicated by directional arrow 131. The drilling fluid may exit the BHA 124 via ports 128 in the drill bit 126 and then circulate uphole through an annular space 108 (“annulus”) of the wellbore 102 defined between an exterior of the drill string 120 and the wall of the wellbore 102, such flow being indicated by directional arrows 133. In this manner, the drilling fluid lubricates the drill bit 126 and carries formation cuttings uphole to the wellsite surface 104. The returning drilling fluid may exit the annulus 108 via different pieces of equipment during different phases or scenarios of well drilling operations. For example, the drilling fluid may exit the annulus 108 via a bell nipple 139, an RCD 138, or a ported adapter 136 (e.g., a spool, cross adapter, a wing valve, etc.) located below one or more rams of the BOP stack 130.

During normal drilling operations, the drilling fluid may exit the annulus 108 via the bell nipple 139 and then be directed toward drilling fluid reconditioning equipment 170 via a fluid conduit 158 (e.g., gravity return line) to be cleaned and/or reconditioned, as described below, prior to being returned to the container 142 for recirculation. During managed pressure drilling operations, the drilling fluid may exit the annulus 108 via the RCD 138 and then be directed into a choke manifold 152 (e.g., a managed pressure drilling choke manifold) via a fluid conduit 150 (e.g., a drilling pressure control line). The choke manifold 152 may include at least one choke and a plurality of fluid valves (neither shown) collectively operable to control the flow through and out of the choke manifold 152. Backpressure may be applied to the annulus 108 by variably restricting flow of the drilling fluid or other fluids flowing through the choke manifold 152. The greater the restriction to flow through the choke manifold 152, the greater the backpressure applied to the annulus 108. The drilling fluid exiting the choke manifold 152 may then pass through the drilling fluid reconditioning equipment 170 prior to being returned to the container 142 for recirculation. During well pressure control operations, such as when one or more rams of the BOP stack 130 is closed, the drilling fluid may exit the annulus 108 via the ported adapter 136 and be directed into a choke manifold 156 (e.g., a rig choke manifold, well control choke manifold) via a fluid conduit 154 (e.g., rig choke line). The choke manifold 156 may include at least one choke and a plurality of fluid valves (neither shown) collectively operable to control the flow of the drilling fluid through the choke manifold 156. Backpressure may be applied to the annulus 108 by variably restricting flow of the drilling fluid (and other fluids) flowing through the choke manifold 156. The drilling fluid exiting the choke manifold 156 may then pass through the drilling fluid reconditioning equipment 170 prior to being returned to the container 142 for recirculation.

Before being returned to the container 142, the drilling fluid returning to the wellsite surface 104 may be cleaned and/or reconditioned via drilling fluid reconditioning equipment 170, which may include one or more of liquid gas (i.e., mud gas) separators 171, shale shakers 172, and other drilling fluid cleaning equipment 173. The liquid gas separators 171 may remove formation gasses entrained in the drilling fluid discharged from the wellbore 102 and the shale shakers 172 may separate and remove solid particles 141 (e.g., drill cuttings) from the drilling fluid. The drilling fluid reconditioning equipment 170 may further comprise other equipment 173 operable to remove additional gas and finer formation cuttings from the drilling fluid and/or modify physical properties or characteristics (e.g., rheology) of the drilling fluid. For example, the drilling fluid reconditioning equipment 170 may include a degasser, a desander, a desilter, a centrifuge, a mud cleaner, and/or a decanter, among other examples. Intermediate tanks/containers (not shown) may be utilized to hold the drilling fluid while the drilling fluid progresses through the various stages or portions 171, 172, 173 of the drilling fluid reconditioning equipment 170. The cleaned/reconditioned drilling fluid may be transferred to the fluid container 142, the solid particles 141 removed from the drilling fluid may be transferred to a solids container 143 (e.g., a reserve pit), and/or the removed gas may be transferred to a flare stack 174 via a conduit 175 (e.g., a flare line) to be burned or to a container (not shown) for storage and removal from the wellsite. A gas sensor 176 (e.g., a carbon tracker) may be connected along the conduit 175 to monitor the quality and/or quantity of gas separated from the drilling fluid and transmitted to the flare stack 174.

The surface equipment 110 may include a tubular handling system or equipment operable to store, move, connect, and disconnect tubulars (e.g., drill pipes) to assemble and disassemble the conveyance means 122 of the drill string 120 during drilling operations. For example, a catwalk 161 may be utilized to convey tubulars from a ground level, such as along the wellsite surface 104, to the rig floor 114, permitting the elevator 129 to grab and lift the tubulars above the wellbore 102 for connection with previously deployed tubulars. The catwalk 161 may have a horizontal portion and an inclined portion that extends between the horizontal portion and the rig floor 114. The catwalk 161 may comprise a skate 163 movable along a groove (not shown) extending longitudinally along the horizontal and inclined portions of the catwalk 161. The skate 163 may be operable to convey (e.g., push) the tubulars along the catwalk 161 to the rig floor 114. The skate 163 may be driven along the groove by a drive system (not shown), such as a pulley system or a hydraulic system. Additionally, one or more racks (not shown) may adjoin the horizontal portion of the catwalk 161. The racks may have a spinner unit for transferring tubulars to the groove of the catwalk 161.

An iron roughneck 165 may be positioned on the rig floor 114. The iron roughneck 165 may comprise a torqueing portion 167, such as may include a spinner and a torque wrench comprising a lower tong and an upper tong. The torqueing portion 167 of the iron roughneck 165 may be moveable toward and at least partially around the drill string 120, such as may permit the iron roughneck 165 to make up and break out connections of the drill string 120. The torqueing portion 167 may also be moveable away from the drill string 120, such as may permit the iron roughneck 165 to move clear of the drill string 120 during drilling operations. The spinner of the iron roughneck 165 may be utilized to apply low torque to make up and break out threaded connections between tubulars of the drill string 120, and the torque wrench may be utilized to apply a higher torque to tighten and loosen the threaded connections.

A set of slips 119 may be located on the rig floor 114, such as may accommodate therethrough the drill string 120 during tubular make up and break out operations and during the drilling operations. The slips 119 may be in an open position during drilling operations to permit advancement of the drill string 120, and in a closed position to clamp the upper end (e.g., uppermost tubular) of the drill string 120 to thereby suspend and prevent advancement of the drill string 120 within the wellbore 102, such as during the make up and break out operations.

During drilling operations, the hoisting system lowers the drill string 120 while the top drive 116 rotates the drill string 120 to advance the drill string 120 downward within the wellbore 102 and into the formation 106. During the advancement of the drill string 120, the slips 119 are in an open position, and the iron roughneck 165 is moved away or is otherwise clear of the drill string 120. When the upper end of the drill string 120 (i.e., upper end of the uppermost tubular of the drill string 120) connected to the drive shaft 125 is near the slips 119 and/or the rig floor 114, the top drive 116 ceases rotating and the slips 119 close to clamp the upper end of the drill string 120. The grabber of the top drive 116 then clamps the uppermost tubular connected to the drive shaft 125, and the drive shaft 125 rotates in a direction reverse from the drilling rotation to break out the connection between the drive shaft 125 and the uppermost tubular. The grabber of the top drive 116 may then release the uppermost tubular.

Multiple tubulars may be loaded on the rack of the catwalk 161 and individual tubulars may be transferred from the rack to the groove in the catwalk 161, such as by the spinner unit. The tubular positioned in the groove may be conveyed along the groove by the skate 163 until the box end of the tubular projects above the rig floor 114. The elevator 129 of the top drive 116 may then grasp the protruding box end, and the draw works 118 may be operated to lift the top drive 116, the elevator 129, and the new tubular.

The hoisting system then raises the top drive 116, the elevator 129, and the new tubular until the tubular is aligned with the upper portion of the drill string 120 clamped by the slips 119. The iron roughneck 165 is moved toward the drill string 120, and the lower tong of the torqueing portion 167 clamps onto the upper end of the drill string 120. The spinning system threadedly connects the lower end (i.e., pin end) of the new tubular with the upper end (i.e., box end) of the drill string 120. The upper tong then clamps onto the new tubular and rotates with high torque to complete making up the connection with the drill string 120. In this manner, the new tubular becomes part of the drill string 120. The iron roughneck 165 then releases and moves clear of the drill string 120.

The grabber of the top drive 116 may then clamp onto the drill string 120. The drive shaft 125 is brought into contact with the upper end of the drill string 120 (e.g., the box end of the uppermost tubular) and rotated to make up a connection between the drill string 120 and the drive shaft 125. The grabber then releases the drill string 120, and the slips 119 are moved to the open position. The drilling operations may then resume.

The tubular handling equipment may further include a tubular handling manipulator (THM) 160 disposed in association with a vertical pipe rack 162 for storing tubulars 111 (e.g., drill pipes, drill collars, drill pipe stands, casing joints, etc.). The vertical pipe rack 162 may comprise or support a fingerboard 164 defining a plurality of slots configured to support or otherwise hold the tubulars 111 within or above a setback 166 (e.g., a platform or another area) located adjacent to, along, or below the rig floor 114. The fingerboard 164 may comprise a plurality of fingers (not shown), each associated with a corresponding slot and operable to close around and/or otherwise interpose individual tubulars 111 to maintain the tubulars 111 within corresponding slots of the fingerboard 164. The vertical pipe rack 162 may be connected with and supported by the support structure 112 or another portion of the wellsite system 100. The fingerboard 164/setback 166 provide storage (e.g., temporary storage) of tubulars 111 during various operations, such as during and between tripping out and tripping of the drill string 120. The THM 160 may be operable to transfer the tubulars 111 between the fingerboard 164/setback 166 and the drill string 120 (i.e., space above the suspended drill string 120). For example, the THM 160 may include arms 168 terminating with clamps 169, such as may be operable to grasp and/or clamp onto one of the tubulars 111. The arms 168 of the THM 160 may extend and retract, and/or at least a portion of the THM 160 may be rotatable and/or movable toward and away from the drill string 120, such as may permit the THM 160 to transfer the tubular 111 between the fingerboard 164/setback 166 and the drill string 120.

To trip out the drill string 120, the top drive 116 is raised, the slips 119 are closed around the drill string 120, and the elevator 129 is closed around the drill string 120. The grabber of the top drive 116 clamps the upper end of a tubular of the drill string 120 coupled to the drive shaft 125. The drive shaft 125 then rotates in a direction reverse from the drilling rotation to break out the connection between the drive shaft 125 and the drill string 120. The grabber of the top drive 116 then releases the tubular of the drill string 120, and the drill string 120 is suspended by (at least in part) the elevator 129. The iron roughneck 165 is moved toward the drill string 120. The lower tong clamps onto a lower tubular below a connection of the drill string 120, and the upper tong clamps onto an upper tubular above that connection. The upper tong then rotates the upper tubular to provide a high torque to break out the connection between the upper and lower tubulars. The spinning system then rotates the upper tubular to separate the upper and lower tubulars, such that the upper tubular is suspended above the rig floor 114 by the elevator 129. The iron roughneck 165 then releases the drill string 120 and moves clear of the drill string 120.

The THM 160 may then move toward the drill string 120 to grasp the tubular suspended from the elevator 129. The elevator 129 then opens to release the tubular. The THM 160 then moves away from the drill string 120 while grasping the tubular with the clamps 169, places the tubular in the fingerboard 164/setback 166, and releases the tubular for storage. This process is repeated until the intended length of drill string 120 is removed from the wellbore 102.

The well construction system 100 may also comprise a plurality of fire and gas sensors 178 located at different locations (e.g., the rig floor 114, the wellsite structure 112) of the well construction system 100. The fire and gas sensors 178 may each be operable to generate signals indicative of fire and/or smoke. The fire and gas sensors 178 may also be or comprise qualitative gas analyzers operable to generate signals indicative of flammable and/or other hazardous gasses being released from the wellbore 102 or otherwise present at the well construction system 100.

The surface equipment 110 of the well construction system 100 may also comprise a control center 190 from which various portions of the well construction system 100, such as the top drive 116, the hoisting system, the tubular handling system, the drilling fluid circulation system, the well control system, the BHA 124, among other examples, may be monitored and controlled. The control center 190 may be located on the rig floor 114 or another location of the well construction system 100, such as the wellsite surface 104. The control center 190 may comprise a facility 191 (e.g., a room, a cabin, a trailer, etc.) containing a control workstation 197, which may be operated by a human wellsite operator 195 to monitor and control various wellsite equipment or portions of the well construction system 100. The control workstation 197 may comprise or be communicatively connected with a processing device 192 (e.g., a controller, a computer, etc.), such as may be operable to receive, process, and output information to monitor operations of and provide control to one or more portions of the well construction system 100. For example, the processing device 192 may be communicatively connected with the various surface and downhole equipment described herein, and may be operable to receive signals from and transmit signals to such equipment to perform various operations described herein. The processing device 192 may store executable program code, instructions, and/or operational parameters or set-points, including for implementing one or more aspects of methods and operations described herein. The processing device 192 may be located within and/or outside of the facility 191.

The control workstation 197 may be operable for entering or otherwise communicating control commands to the processing device 192 by the wellsite operator 195, and for displaying or otherwise communicating information from the processing device 192 to the wellsite operator 195. The control workstation 197 may comprise a plurality of human-machine interface (HMI) devices, including one or more input devices 194 (e.g., a keyboard, a mouse, a joystick, a touchscreen, etc.) and one or more output devices 196 (e.g., a video monitor, a touchscreen, a printer, audio speakers, etc.). Communication between the processing device 192, the input and output devices 194, 196, and the various wellsite equipment may be via wired and/or wireless communication means. However, for clarity and ease of understanding, such communication means are not depicted, and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure.

The well construction system 100 also includes stationary and/or mobile video cameras 198 disposed or utilized at various locations within the well construction system 100. The video cameras 198 capture videos of various portions, equipment, or subsystems of the well construction system 100, and perhaps the wellsite operators 195 and the actions they perform, during or otherwise in association with the wellsite operations, including while performing repairs to the well construction system 100 during a breakdown. For example, the video cameras 198 may capture videos of the entire well construction system 100 and/or specific portions of the well construction system 100, such as the top drive 116, the iron roughneck 165, the THM 160, the fingerboard 164, and/or the catwalk 161, among other examples. The video cameras 198 generate corresponding video signals (i.e., video feeds) comprising or otherwise indicative of the captured videos. The video cameras 198 may be in signal communication with the processing device 192, such as may permit the video signals to be processed and transmitted to the control workstation 197 and, thus, permit the wellsite operators 195 to view various portions or components of the well construction system 100 on one or more of the output devices 196. The processing device 192 or another portion of the control workstation 197 may be operable to record the video signals generated by the video cameras 198.

Well construction systems within the scope of the present disclosure may include more or fewer components than as described above and depicted in FIG. 1. Additionally, various equipment and/or subsystems of the well construction system 100 shown in FIG. 1 may include more or fewer components than as described above and depicted in FIG. 1. For example, various engines, motors, hydraulics, actuators, valves, and/or other components not explicitly described herein may be included in the well construction system 100, and are within the scope of the present disclosure.

FIG. 2 is a schematic view of at least a portion of an example implementation of a control system 200 for the well construction system 100 according to one or more aspects of the present disclosure. The following description refers to FIGS. 1 and 2, collectively.

The control system 200 may be utilized to monitor and control various portions, components, and equipment of the well construction system 100 described herein, which may be grouped into several subsystems, each operable to perform a corresponding operation and/or a portion of the well construction operations described herein. The subsystems may include a tubular handling and rotation (THR) system 211, a fluid processing (FP) system 212, a managed pressure drilling control (MPDC) system 213, a fire and gas monitoring (FGM) system 214, a closed-circuit television (CCTV) system 215, a choke pressure control (CPC) system 216, and a well pressure control (WC) system 217. The control workstation 197 may be utilized to monitor, configure, control, and/or otherwise operate one or more of the subsystems 211-217.

The THR system 211 (i.e., drill rig equipment system) may include the support structure 112, the draw works 118, a drill string rotational system (e.g., the top drive 116 and/or the rotary table and kelly), the slips 119, the tubular handling system or equipment (e.g., the catwalk 161, the THM 160, the setback 166, and the iron roughneck 165), electrical generators, and other equipment. Accordingly, the THR system 211 may perform power generation controls and tubular handling, hoisting, and rotation operations. The THR system 211 may also serve as a support platform for drilling equipment and staging ground for rig operations, such as connection make up and break out operations described above. The FP system 212 may include the drilling fluid reconditioning equipment 170, the flare stack 174, the gas sensor 176, the containers 142, 143, and the pumps 144. Accordingly, the FP system 212 may perform fluid reconditioning operations, fluid discharge operations, and fluid pumping operations of the well construction system 100. The MPDC system 213 may include the RCD 138, the choke manifold 152, downhole pressure sensors 186, and/or other equipment. The FGM system 214 may comprise the fire and gas sensors 178 and/or other equipment. The CCTV system 215 may include the video cameras 198, one or more other input devices 194 (e.g., a keyboard, a touchscreen, etc.), one or more video output devices 196 (e.g., video monitors), various communication equipment (e.g., modems, network interface cards, etc.), and/or other equipment. The CCTV system 215 may be utilized to capture real-time video of various portions or subsystems 211-217 of the well construction system 100 and display video signals from the video cameras 198 on the video output devices to display in real-time the various portions or subsystems 211-217 of the well construction system 100. The CPC system 216 may comprise the choke manifold 156, and/or other equipment, and the WC system 217 may comprise the BOP equipment 130, 132, 138, the BOP control unit 137, and a BOP control station (e.g., BOP control station 370 shown in FIG. 5) for controlling the BOP control unit 137. Each of the well construction subsystems 211-217 may further comprise various communication equipment (e.g., modems, network interface cards, etc.) and communication conductors (e.g., cables), communicatively connecting the equipment (e.g., sensors and actuators) of each subsystem 211-217 with the control workstation 197 and/or other equipment. Although the wellsite equipment listed above and shown in FIG. 1 is associated with certain wellsite subsystems 211-217, such associations are merely examples that are not intended to limit or prevent such wellsite equipment from being associated with two or more wellsite subsystems 211-217 and/or different wellsite subsystems 211-217.

The control system 200 may include a wellsite computing resource environment 205, which may be located at the wellsite 104 as part of the well construction system 100, and a remote computing resource environment 206, which may be located offsite (i.e., not at the wellsite 104). The control system 200 may also include various local controllers (e.g., controllers 241-247 shown in FIG. 3) associated with the subsystems 211-217 and/or individual pieces of equipment of the well construction system 100. As described above, each subsystem 211-217 of the well construction system 100 may include actuators (e.g., actuators 231-237 shown in FIG. 3) and sensors (e.g., sensors 221-227 shown in FIG. 3) for performing operations of the well construction system 100. These actuators and sensors may be monitored and/or controlled via the wellsite computing resource environment 205, the remote computing resource environment 206, and/or the corresponding local controllers. For example, the wellsite computing resource environment 205 and/or the local controllers may be operable to monitor the sensors of the wellsite subsystems 211-217 in real-time, and to provide real-time control commands to the subsystems 211-217 based on the received sensor data. Data may be generated by both sensors and computation, and may be utilized for coordinated control among two or more pieces of equipment and/or equipment subsystems 211-217.

The control system 200 may be in real-time communication with the various components of the well construction system 100. For example, the local controllers may be in communication with various sensors and actuators of the corresponding subsystems 211-217 via local communication networks (not shown) and the wellsite computing resource environment 205 may be in communication with the subsystems 211-217 via a data bus or network 209. As described below, data or sensor signals generated by the sensors of the subsystems 211-217 may be made available for use by processes (e.g., processes 274, 275 shown in FIG. 3) and/or devices of the wellsite computing resource environment 205. Similarly, data or control signals generated by the processes and/or devices of the wellsite computing resource environment 205 may be automatically communicated to various actuators of the subsystems 211-217, perhaps pursuant to predetermined programming, such as to facilitate well construction operations and/or other operations described herein.

The remote computing resource environment 206, the wellsite computing resource environment 205, and the subsystems 211-217 of the well construction system 100 may be communicatively connected with each other via a network connection, such as via a wide-area-network (WAN), a local-area-network (LAN), and/or other networks also within the scope of the present disclosure. A “cloud” computing environment is one example of a remote computing resource environment 206. The wellsite computing resource environment 205 may be or form at least a portion of the processing device 192 and, thus, may form a portion of or be communicatively connected with the control workstation 197.

FIG. 3 is a schematic view of an example implementation of the control system 200 shown in FIG. 2 communicatively connected with the subsystems 211-217 of the well construction system 100, including the THR system 211, the FP system 212, the MPDC system 213, the FGM system 214, the CCTV system 215, the CPC system 216, and the WC system 217. The following description refers to FIGS. 1-3, collectively.

An example implementation of the well construction system 100 may include one or more onsite user devices 202 communicatively connected with the wellsite computing resource environment 205. The onsite user devices 202 may be or comprise stationary user devices intended to be stationed at the well construction system 100 and/or portable user devices. For example, the onsite user devices 202 may include a desktop, a laptop, a smartphone, a personal digital assistant (PDA), a tablet component, a wearable computer, or other suitable devices. The onsite user devices 202 may be operable to communicate with the wellsite computing resource environment 205 of the well construction system 100 and/or the remote computing resource environment 206. The onsite user device 202 may be or comprise at least a portion of the control workstation 197 shown in FIG. 1 and described above. The onsite user device 202 may be located within the facility 191.

The wellsite computing resource environment 205 and/or other portions of the well construction system 100 may further comprise an information technology (IT) system 219 operable to communicatively connect various portions of the wellsite computing resource environment 205 and/or communicatively connect the wellsite computing resource environment 205 with other portions of the well construction system 100. The IT system 219 may include communication conduits, software, computers, and other IT equipment facilitating communication between one or more portions of the wellsite computing resource environment 205 and/or between the wellsite computing resource environment 205 and another portion of the well construction system 100, such as the remote computing resource environment 206, the onsite user device 202, and the subsystems 211-217.

The control system 200 may include (or otherwise be utilized in conjunction with) one or more offsite user devices 203. The offsite user devices 203 may be or comprise a desktop computer, a laptop computer, a smartphone and/or other portable smart device, a PDA, a tablet/touchscreen computer, a wearable computer, and/or other devices. The offsite user devices 203 may be operable to receive and/or transmit information (e.g., for monitoring functionality) from and/or to the well construction system 100, such as by communication with the wellsite computing resource environment 205 via the network 208. The offsite user devices 203 may be utilized for monitoring functions, but may also provide control processes for controlling operation of the various subsystems 211-217 of the well construction system 100. The offsite user devices 203 and/or the wellsite computing resource environment 205 may also be operable to communicate with the remote computing resource environment 206 via the network 208. The network 208 may be a WAN, such as the internet, a cellular network, a satellite network, other WANs, and/or combinations thereof.

The subsystems 211-217 of the well construction system 100 may include sensors 221-227, actuators 231-237, and local controllers 241-247. The controllers 241-247 may each be or comprise a programmable logic controller (PLC), a computer (PC), an industrial computer (IPC), a soft PLC, and/or another controller or processing device operable to store execute machine-readable and executable program code instructions (i.e., computer program code). The THR system 211 may include one or more sensors 221, one or more actuators 231, and one or more controllers 241. The FP system 212 may include one or more sensors 222, one or more actuators 232, and one or more controllers 242. The MPDC system 213 may include one or more sensors 223, one or more actuators 233, and one or more controllers 243. The FGM system 214 may include one or more sensors 224, one or more actuators 234, and one or more controllers 244. The CCTV system 215 may include one or more sensors 225, one or more actuators 235, and one or more controllers 245. The CPC system 216 may include one or more sensors 226, one or more actuators 236, and one or more controllers 246. The WC system 217 may include one or more sensors 227, one or more actuators 237, and one or more controllers 247 (e.g., a BOP control station 370 shown in FIG. 5).

The sensors 221-227 may include sensors utilized for operation of the various subsystems 211-217 of the well construction system 100. For example, the sensors 221-227 may include cameras, position sensors, pressure sensors, temperature sensors, flow rate sensors, vibration sensors, current sensors, voltage sensors, resistance sensors, gesture detection sensors or devices, voice actuated or recognition devices or sensors, and/or other examples.

The sensors 221-227 may be operable to provide sensor data to the wellsite computing resource environment 205, such as to the coordinated control device 204. For example, the sensors 221-227 may provide sensor data 251-257, respectively. The sensor data 251-257 may include signals or information indicative of equipment operation status (e.g., on or off, up or down, set or release, etc.), drilling parameters (e.g., depth, hook load, torque, etc.), auxiliary parameters (e.g., vibration data of a pump), flow rate, temperature, operational speed, position, and pressure, among other examples. The acquired sensor data 251-257 may include or be associated with a timestamp (e.g., date and/or time) indicative of when the sensor data 251-257 was acquired. The sensor data 251-257 may also or instead be aligned with a depth or other drilling parameter.

Acquiring the sensor data 251-257 at the coordinated control device 204 may facilitate measurement of the same physical properties at different locations of the well construction system 100, wherein the sensor data 251-257 may be utilized for measurement redundancy to permit continued well construction operations. Measurements of the same physical properties at different locations may also be utilized for detecting equipment conditions among different physical locations at the wellsite surface 104 or within the wellbore 102. Variation in measurements at different wellsite locations over time may be utilized to determine equipment performance, system performance, scheduled maintenance due dates, and the like. For example, slip status (e.g., set or unset) may be acquired from the sensors 221 and communicated to the wellsite computing resource environment 205. Acquisition of fluid samples may be measured by a sensor, such as the sensors 186, 223, and related with bit depth and time measured by other sensors. Acquisition of data from the video cameras 198, 225 may facilitate detection of arrival and/or installation of materials or equipment at the well construction system 100. The time of arrival and/or installation of materials or equipment may be utilized to evaluate degradation of material, scheduled maintenance of equipment, and other evaluations.

The coordinated control device 204 may facilitate control of one or more of the subsystems 211-217 at the level of each individual subsystem 211-217. For example, in the FP system 212, sensor data 252 may be fed into the controller 242, which may respond to control the actuators 232. However, for control operations that involve multiple systems, the control may be coordinated through the coordinated control device 204. For example, coordinated control operations may include the control of downhole pressure during tripping. The downhole pressure may be affected by both the FP system 212 (e.g., pump rate), the MPDC 213 (e.g., choke position of the MPDC), and the THR system 211 (e.g., tripping speed). Thus, when it is intended to maintain certain downhole pressure during tripping, the coordinated control device 204 may be utilized to direct the appropriate control commands to two or more (or each) of the participating subsystems.

Control of the subsystems 211-217 of the well construction system 100 may be provided via a three-tier control system that includes a first tier of the local controllers 241-247, a second tier of the coordinated control device 204, and a third tier of the supervisory control system 207. Coordinated control may also be provided by one or more controllers 241-247 of one or more of the subsystems 211-217 without the use of a coordinated control device 204. In such implementations of the control system 200, the wellsite computing resource environment 205 may provide control processes directly to these controllers 241-247 for coordinated control.

The sensor data 251-257 may be received by the coordinated control device 204 and utilized for control of the subsystems 211-217. The sensor data 251-257 may be encrypted to produce encrypted sensor data 271. For example, the wellsite computing resource environment 205 may encrypt sensor data from different types of sensors and systems to produce a set of encrypted sensor data 271. Thus, the encrypted sensor data 271 may not be viewable by unauthorized user devices (either offsite user devices 203 or onsite user devices 202) if such devices gain access to one or more networks of the well construction system 100. The encrypted sensor data 271 may include a timestamp and an aligned drilling parameter (e.g., depth), as described above. The encrypted sensor data 271 may be communicated to the remote computing resource environment 206 via the network 208 and stored as encrypted sensor data 272.

The wellsite computing resource environment 205 may provide the encrypted sensor data 271, 272 available for viewing and processing offsite, such as via the offsite user devices 203. Access to the encrypted sensor data 271, 272 may be restricted via access control implemented in the wellsite computing resource environment 205. The encrypted sensor data 271, 272 may be provided in real-time to offsite user devices 203 such that offsite personnel may view real-time status of the well construction system 100 and provide feedback based on the real-time sensor data. For example, different portions of the encrypted sensor data 271, 272 may be sent to the offsite user devices 203. The encrypted sensor data 271, 272 may be decrypted by the wellsite computing resource environment 205 before transmission, and/or decrypted on the offsite user device 203 after encrypted sensor data is received. The offsite user device 203 may include a thin client (not shown) configured to display data received from the wellsite computing resource environment 205 and/or the remote computing resource environment 206. For example, multiple types of thin clients (e.g., devices with display capability and minimal processing capability) may be utilized for certain functions or for viewing various sensor data 251-257.

The wellsite computing resource environment 205 may include various computing resources utilized for monitoring and controlling operations, such as one or more computers having a processor and a memory. For example, the coordinated control device 204 may include a processing device (e.g., processing device 1000 shown in FIG. 15), having a processor and memory for processing the sensor data, storing the sensor data, and issuing control commands responsive to the sensor data. As described above, the coordinated control device 204 may control various operations of the subsystems 211-217 via analysis of sensor data 251-257 from one or more of the wellsite subsystems 211-217 to facilitate coordinated control between the subsystems 211-217. The coordinated control device 204 may generate control data 273 (e.g., signals, commands, coded instructions) to execute control of the subsystems 211-217. The coordinated control device 204 may transmit the control data 273 to one or more subsystems 211-217. For example, control data 261 may be sent to the THR system 211, control data 262 may be sent to the FP system 212, control data 263 may be sent to the MPDC system 213, control data 264 may be sent to the FGM system 214, control data 265 may be sent to the CCTV system 215, control data 266 may be sent to the CPC system 216, and control data 267 may be sent to the WC system 217. The control data 261-267 may include, for example, wellsite operator commands (e.g., turn on or off a pump, switch on or off a valve, update a physical property set-point, etc.). The coordinated control device 204 may include a fast control loop that directly obtains sensor data 251-257 and executes, for example, a control algorithm. The coordinated control device 204 may include a slow control loop that obtains data via the wellsite computing resource environment 205 to generate control commands.

The coordinated control device 204 may intermediate between the supervisory control system 207 and the local controllers 241-247 of the subsystems 211-217, such as may permit the supervisory control system 207 to control the subsystems 211-217. The supervisory control system 207 may include, for example, devices for entering control commands to perform operations of the subsystems 211-217. The coordinated control device 204 may receive commands from the supervisory control system 207, process such commands according to a rule (e.g., an algorithm based upon the laws of physics for drilling operations), and provide control data to one or more subsystems 211-217. The supervisory control system 207 may be provided by the wellsite operator 195 and/or process monitoring and control program. In such implementations, the coordinated control device 204 may coordinate control between discrete supervisory control systems and the subsystems 211-217 while utilizing control data 261-267 that may be generated based on the sensor data 251-257 received from the subsystems 211-217 and analyzed via the wellsite computing resource environment 205. The coordinated control device 204 may receive the control data 251-257 and then dispatch control data 261, including interlock commands, to each subsystem 211-217. The coordinated control device 204 may also or instead just listen to the control data 251-257 being dispatched to each subsystem 221-227 and then initiate the machine interlock commands to the relevant local controller 241-247.

The coordinated control device 204 may run with different levels of autonomy. For example, the coordinated control device 204 may operate in an advice mode to inform the wellsite operators 195 to perform a specific task or take specific corrective action based on sensor data 251-257 received from the various subsystems 211-217. While in the advice mode, the coordinated control device 204 may, for example, advise or instruct the wellsite operator 195 to perform a standard work sequence when gas is detected on the rig floor 114, such as to close the annular BOP 132. Furthermore, if the wellbore 102 is gaining or losing drilling fluid 140, the coordinated control device 204 may, for example, advise or instruct the wellsite operator 195 to modify the density of the drilling fluid 140, modify the pumping rate of the drilling fluid 140, and/or modify the pressure of the drilling fluid within the wellbore 102.

The coordinated control device 204 may also operate in a system/equipment interlock mode, whereby certain operations or operational sequences are prevented based on the received sensor data 251-257. While operating in the interlock mode, the coordinated control device 204 may manage interlock operations among the various equipment of the subsystems 211-217. For example, if a pipe ram of the BOP stack 130 is activated, the coordinated control device 204 may issue an interlock command to the THR system controller 241 to stop the draw works 118 from moving the drill string 120. However, if a shear ram of the BOP stack 130 is activated, the coordinated control device 204 may issue an interlock command to the controller 241 to operate the draw works 118 to adjust the position of the drill string 120 within the BOP stack 130 before activating the shear ram, so that the shear ram does not align with a shoulder of the tubulars forming the drill string 120.

The coordinated control device 204 may also operate in an automated sequence mode, whereby certain operations or operational sequences are automatically performed based on the received sensor data 251-257. For example, the coordinated control device 204 may activate an alarm and/or stop or reduce operating speed of the tubular handling equipment when a wellsite operator 195 is detected close to a moving iron roughneck 165, the THM 160, or the catwalk 161. As another example, if the wellbore pressure increases rapidly, the coordinated control device 204 may close the annular BOP 132, close one or more rams of the BOP stack 130, and/or adjust the choke manifold 152.

The wellsite computing resource environment 205 may comprise or execute a monitoring process 274 (e.g., an event detection process) that may utilize the sensor data 251-257 to determine information about status of the well construction system 100 and automatically initiate an operational action, a process, and/or a sequence of one or more of the subsystems 211-217. The monitoring process 274 may initiate the operational action to be caused by the coordinated control device 204. Depending on the type and range of the sensor data 251-257 received, the operational actions may be executed in the advice mode, the interlock mode, or the automated sequence mode.

For example, the monitoring process 274 may determine a drilling state, equipment health, system health, a maintenance schedule, or combination thereof, and initiate an advice to be generated. The monitoring process 274 may also detect abnormal drilling events, such as a wellbore fluid loss and gain, a wellbore washout, a fluid quality issue, or an equipment event based on job design and execution parameters (e.g., wellbore, drilling fluid, and drill string parameters), current drilling state, and real-time sensor information from the surface equipment 110 (e.g., presence of hazardous gas at the rig floor, presence of wellsite operators in close proximity to moving tubular handling equipment, etc.) and the BHA 124, initiating an operational action in the automated mode. The monitoring process 274 may be connected to the real-time communication network 209. The coordinated control device 204 may initiate a counteractive measure (e.g., a predetermined action, process, or operation) based on the events detected by the monitoring process 274.

The term “event” as used herein may include, but not be limited to, an operational and safety related event described herein and/or another operational and safety related event that can take place at a well construction system. The events described herein may be detected by the monitoring process 274 based on the sensor data 251-257 (e.g., sensor signals or information) received and analyzed by the monitoring process 274.

The wellsite computing resource environment 205 may also comprise or execute a control process 275 that may utilize the sensor data 251-257 to optimize drilling operations, such as the control of drilling equipment to improve drilling efficiency, equipment reliability, and the like. For example, the acquired sensor data 252 may be utilized to derive a noise cancellation scheme to improve electromagnetic and mud pulse telemetry signal processing. The remote computing resource environment 206 may comprise or execute a control process 276 substantially similar to the control process 275 that may be provided to the wellsite computing resource environment 205. The monitoring and control processes 274, 275, 276 may be implemented via, for example, a control algorithm, a computer program, firmware, or other hardware and/or software.

The wellsite computing resource environment 205 may include various computing resources, such as a single computer or multiple computers. The wellsite computing resource environment 205 may further include a virtual computer system and a virtual database or other virtual structure for collected data, such as may include one or more resource interfaces (e.g., web interfaces) that facilitate the submission of application programming interface (API) calls to the various resources through a request. In addition, each of the resources may include one or more resource interfaces that facilitate the resources to access each other (e.g., to facilitate a virtual computer system of the computing resource environment to store data in or retrieve data from the database or other structure for collected data). The virtual computer system may include a collection of computing resources configured to instantiate virtual machine instances. A wellsite operator 195 may interface with the virtual computer system via the offsite user device 203 or the onsite user device 202. Other computer systems or computer system services may be utilized in the wellsite computing resource environment 205, such as a computer system or computer system service that provides computing resources on dedicated or shared computers/servers and/or other physical devices. The wellsite computing resource environment 205 may include a single server (in a discrete hardware component or as a virtual server) or multiple servers (e.g., web servers, application servers, or other servers). The servers may be, for example, computers arranged in physical and/or virtual configuration.

The wellsite computing resource environment 205 may also include a database that may be or comprise a collection of computing resources that run one or more data collections. Such data collections may be operated and managed by utilizing API calls. The data collections, such as the sensor data 251-257, may be made available to other resources in the wellsite computing resource environment 205, or to user devices (e.g., onsite user device 202 and/or offsite user device 203) accessing the wellsite computing resource environment 205. The remote computing resource environment 206 may include computing resources similar to those described above, such as a single computer or multiple computers (in discrete hardware components or virtual computer systems).

FIGS. 4 and 5 are perspective and sectional views of at least a portion of an example implementation of a control center 300 according to one or more aspects of the present disclosure. The control center 300 may be or form at least a portion of the control center 190 shown in FIG. 1. The following description refers to FIGS. 1, 4, and 5, collectively.

The control center 300 comprises a facility 305 (e.g., a room, a cabin, a trailer, etc.) containing various control devices for monitoring and controlling the subsystems 211-217 and other portions of the well construction system 100. The facility 305 may comprise a front side 301, which may be directed toward or located closest to the drill string 120 being constructed by the well construction system 100 and a rear side 303, which may be directed away from the drill string 120. The facility 305 may comprise a floor 302, a front wall 304, a left wall 306, a right wall 308, a rear wall 310, and a roof 312. The facility 305 may also have a side door 314, a rear door 316, and a plurality of windows 321-328 in one or more of the walls 304, 306, 308, 310 and/or the roof 312. Each of the windows 321-328 may be surrounded by structural framing 330 connected with the walls and supporting window safety guards 332 (e.g., bars, grills) in front of or along the windows 321-328.

The facility 305 may have an observation area 340 at the front side 301 of the facility 305 from which a wellsite operator 195 will have an optimal or otherwise improved view of the drill string 120, the rig floor 114, and/or other portions of the well construction system 100. The observation area 340 may be surrounded or defined by windows 323-328 on several sides to increase wellsite operator's 195 horizontal and vertical angle of view of the well constriction system 100. A portion 342 of the observation area 340 (e.g., windows 323-327) may protrude or extend out past other portions of the facility 305 (e.g., front wall 304) to facilitate the optimal view of the well construction system 100 by the wellsite operators 195. The observation area 340 may be located on a side of the facility 305. The observation area 318 may be surrounded by or at least partially defined by a front window 324 permitting the wellsite operator 195 to look forward, two side windows 323, 325 permitting the wellsite operator 195 to look sideways (i.e., left and right), a lower window 326 permitting the wellsite operator 195 to look downwards, and one or more upper windows 327, 328 permitting the wellsite operator 195 to look upwards. The lower window 326 and/or at least one upper window 327 may extend diagonally with respect to the front window 324.

The control center 300 may comprise one or more wellsite operator control workstations within the facility 305. The workstations may be utilized by the wellsite operators 195 to monitor and control the subsystems 211-217 and other portions of the well construction system 100. For example, the observation area 340 may contain a first control workstation 350 located adjacent the windows 323, 324, 325, 326, 328 and at least partially within the extended portion 342 of the observation area 340, such as may permit the wellsite operator 195 utilizing the control workstation 350 to have an unobstructed or otherwise optimal view of the drill string 120, the rig floor 114, and/or other portions of the well construction system 100. The observation area 340 may also contain a second control workstation 352 located adjacent (e.g., behind) the first control workstation 350 and adjacent the window 325, but not within the extended portion 342 of the observation area 340. The control workstation 352 may be elevated at least partially above the control workstation 350 to reduce the obstruction of view caused by the control workstation 350 and, thus, permit the wellsite operator 195 utilizing the control workstation 352 to view the drill string 120, the rig floor 114, and/or other portions of the well construction system 100 over the control workstation 350 via the front window 324. The control center 300 may also comprise a third control workstation 354 located adjacent the control workstations 350, 352 and adjacent the windows 321, 322, but not within the observation area 340.

The control center 300 may further comprise a processing device 356 (e.g., a controller, a computer, a server, etc.) operable to provide control to one or more portions of the well construction system 100 and/or operable to monitor operations of one or more portions of the well construction system 100. For example, the processing device 356 may be communicatively connected with the various surface and downhole equipment described herein and operable to receive signals from and transmit signals to such equipment to perform various operations described herein. The processing device 356 may store executable programs, instructions, and/or operational parameters or set-points, including for implementing one or more aspects of the operations described herein. The processing device 356 may be communicatively connected with the control workstations 350, 352, 354. Although the processing device 356 is shown located within the facility 305, the processing device 356 may be located outside of the facility 305. Furthermore, although the processing device 356 is shown as a single device that is separate and distinct from the control workstations 350, 352, 354, one or more of the control workstation 350, 352, 354 may comprise a corresponding processing device 356 disposed in association with or forming at least a portion of such corresponding processing device 356.

The control workstations 350, 352, 354 may be operable to enter or otherwise communicate commands to the processing device 356 by the wellsite operator 195 and to display or otherwise communicate information from the processing device 356 to the wellsite operator 195. One or more of the control workstations 350, 352, 354 may comprise an operator chair 360 and an HMI system comprising one or more input devices 362 (e.g., a keyboard, a mouse, a joystick, a touchscreen, a microphone, etc.) and one or more output devices 364 (e.g., a video monitor, a printer, audio speakers, a touchscreen, etc.). The input and output devices 362, 364 may be disposed in association with and/or integrated with the operator chair 360 to permit the wellsite operator 195 to enter commands or other information to the processing device 356 and receive information from the processing device 356 and other portions of the well construction system 100. One or more of the control workstations 350, 352, 354 may be or form at least a portion of the control workstation 197 shown in FIG. 1, and the processing device 356 may be or form at least a portion of the processing device 192 shown in FIG. 1.

The control center 300 may further contain a BOP control station 370 (e.g., control panel) of the WC system 217 operable to monitor and control one or more portions of the WC system 217. For example, the BOP control station 370 may be communicatively connected with the BOP control unit 137 and the BOP equipment 130, 132, 138, and operable to monitor and control operations of the BOP control unit 137 and the BOP equipment 130, 132, 138.

The BOP control station 370 may be operable communicate to the BOP control unit 137 control commands entered by the wellsite operator 195 for controlling the BOP equipment 130, 132, 138 and to display or otherwise communicate information indicative of operational status of the BOP equipment 130, 132, 138 and the BOP control unit 137 to the wellsite operator 195. The BOP control station 370 may comprise a processing device (e.g., processing device 1000 shown in FIG. 15) operable to store executable programs, instructions, and/or operational parameters or set-points, including for implementing one or more BOP operations described herein. The BOP control station 370 may further comprise an HMI system comprising one or more input devices 372 (e.g., buttons, keys, a touchscreen, etc.) and one or more output devices 374 (e.g., a video monitor, gauges, audio speakers, a touchscreen, etc.). The input and output devices 372, 374 may be disposed in association with and/or integrated with a housing or enclosure of the BOP control station 370 to permit the wellsite operator 195 to enter commands or other information to the BOP control station 370 to control the BOP equipment 130, 132, 138 and receive information from the BOP control station 370 to monitor operational status of the BOP equipment 130, 132, 138.

The BOP control unit 370 may be communicatively connected with one or more of the control workstations 350, 352, 354, such as may permit monitoring and control of one or more portions of the WC system 217 via the control workstations 350, 352, 354. For example, one or more of the control workstations 350, 352, 354 or the processing device 356 may be communicatively connected directly with the processing device of the BOP control station 370 or indirectly, such as via the input and output devices 372, 374 of the BOP control station 370. Such connection may permit the control workstations 350, 352, 354 to receive information indicative of operational status of the BOP control unit 137 and the BOP equipment 130, 132, 138 via the BOP control station 370. Such connection may further permit the control workstations 350, 352, 354 to transmit control commands to the BOP control unit 137 and the BOP equipment 130, 132, 138 via the BOP control station 370. Such connection may also or instead facilitate control of the BOP control station 370 via the control workstations 350, 352, 354, such as may cause the BOP control station 370 to control the BOP control unit 137 and the BOP equipment 130, 132, 138 as directed by or from the control workstations 350, 352, 354.

The control workstations 350, 352, 354 may be operable to display the information indicative of operational status of the BOP control unit 137 and the BOP equipment 130, 132, 138 to the wellsite operator 195 via the output devices 364 to permit the wellsite operator to monitor the operational status of the BOP control unit 137 and the BOP equipment 130, 132, 138 while sitting in the corresponding operator chair 360. The control workstations 350, 352, 354 may be further operable to receive the control commands from the wellsite operator 195 via the input devices 362 while sitting in the corresponding operator chair 360 for transmission to the BOP control station 370 to control the BOP control unit 137 and the BOP equipment 130, 132, 138.

FIG. 6 is a top view of a portion of an example implementation of a wellsite operator control workstation 400 communicatively connected with and operable to control the well construction system 100 according to one or more aspects of the present disclosure. The control workstation 400 may facilitate receiving and displaying various information, such as sensor signals or information (e.g., sensor data 251-257), control commands (e.g., control data 261-267), processes taking place, events being detected, and operational status of various equipment of the subsystems 211-217 of the well construction system 100. The following description refers to FIGS. 1-6, collectively.

The control workstation 400 comprises an operator chair 402 (e.g., driller's chair) and an HMI system comprising a plurality of input and output devices integrated with, supported by, or otherwise disposed in association with the operator chair 402. The input devices permit the wellsite operator 195 to enter commands or other information to control the wellsite equipment of the well construction system 100, and the output devices permit the wellsite operator 195 to receive sensor signals and other information indicative of operational status of the wellsite equipment. The operator chair 402 may include a seat 404, a left armrest 406, and a right armrest 408.

The input devices of the control workstation 400 may include a plurality of physical controls, such as a left joystick 410, a right joystick 412, and/or other physical controls 414, 415, 416, 418, such as buttons, keys, switches, knobs, dials, slider bars, a mouse, a keyboard, and a microphone. One or more of the joysticks 410, 412 and/or the physical controls 414, 415, 416 may be integrated into or otherwise supported by the corresponding armrests 406, 408 of the operator chair 402 to permit the wellsite operator 195 to operate these input devices from the operator chair 402. Furthermore, one or more of the physical controls 418 may be integrated into the corresponding joysticks 410, 412 to permit the wellsite operator 195 to operate these physical controls 418 while operating the joysticks 410, 412. The physical controls may comprise emergency stop (E-stop) buttons 415, which may be electrically connected to E-stop relays of one or more pieces of wellsite equipment (e.g., the iron roughneck 165, the THM 160, the draw works 118, the top drive 116, etc.), such that the wellsite operator 195 can shut down the wellsite equipment during emergencies and other situations.

The output devices of the control workstation 400 may include one or more video output devices 426 (e.g., video monitors), printers, speakers, and other output devices disposed in association with the operator chair 402 and operable to display to the wellsite operator 195 sensor signals and other information indicative of operational status of the well construction system 100. The video output devices 426 may be implemented as one or more LCD displays, LED displays, plasma displays, cathode ray tube (CRT) displays, and/or other types of displays.

The video output devices 426 may be disposed in front of or otherwise adjacent the operator chair 402. The video output devices 426 may include a plurality of video output devices 432, 434, 436, each dedicated to displaying predetermined information in a predetermined (e.g., programmed) manner. Although the video output devices 426 are shown comprising three video output devices 432, 434, 436, the video output devices 426 may be or comprise one, two, four, or more video output devices.

The video output devices 432, 434, 436 may each display in a predetermined manner selected sensor signals or information indicative of operational status of a selected portion of the well construction system 100. For example, the video output devices 434, 436 may display sensor signals or information 440 (e.g., sensor data 251-257) generated by the various sensors (e.g., sensors 221-227) of the well construction system 100 to permit the wellsite operator 195 to monitor operational status of the subsystems 211-217. The information 440 may be displayed in the form of virtual or computer generated lists, menus, tables, graphs, bars, gauges, lights, and schematics, among other examples.

One or more of the video output devices 426 may be configured to display video signals (i.e., video feeds) generated by one or more of the video cameras 198. For example, the video output device 432 may be dedicated for displaying the video signals generated by one or more of the video cameras 198. When displaying the video signals from multiple video cameras 198, the video output device 432 may display multiple video windows, each displaying a corresponding video signal. Furthermore, one or more of the other video output devices 434, 436 may also display the video signals from one or more of the video cameras 198. For example, one or both of the video output devices 434, 436 may display one or more picture-in-picture (PIP) video windows 444, each displaying a video signal from a corresponding one of the video cameras 198. The PIP video windows 444 may be embedded or inset along or adjacent the sensor information 440. Sourcing (i.e., selection) of the video cameras 198 whose video signals are to be displayed on the video output devices 426 may be selected manually by the wellsite operator 195 or automated via the control system 200, such as based on operational events (e.g., drilling events, well construction operation stage, etc.) at the well construction system 100, such that video signals relevant to an event currently taking place are displayed.

The control workstation 400 may further comprise combination devices operable as both input and output devices to display information to the wellsite operator 195 and receive commands or information from the wellsite operator 195. Such devices may be or comprise touchscreens 422, 424 (i.e., touchpads) operable to display a plurality of software (e.g., virtual, computer generated) buttons, switches, knobs, dials, icons, and/or other software controls 430 permitting the wellsite operator 195 to operate (e.g., click, selected, move) the software controls 430 via finger contact with the touchscreens 422, 424 to control the various wellsite equipment of the subsystems 211-217. The software controls 430 may also be operated by the physical controls 414, 416, the joysticks 410, 412, or other input devices of the control workstation 400. The software controls 430 and/or other features displayed on the touchscreens 422, 424 may also display sensor signals or information (e.g., sensor data 251-257), operational settings, set-points, and/or status of selected wellsite equipment for viewing by the wellsite operator 195. For example, the software controls 430 may change color, move in position or direction, and/or display the sensor information, set-points, and/or operational values (e.g., temperature, pressure, position). The touchscreens 422, 424 may be disposed on, supported by, or integrated into the armrests 406, 408 or other parts of the operator chair 402 to permit the wellsite operator 195 to operate the software controls 430 displayed on the touchscreens 422, 424 from the operator chair 402.

Each video output device 426 and touchscreen 422, 424 may display (i.e., generate) a plurality of display screens (i.e., an integrated display system), each displaying to the wellsite operator 195 selected sensor signals or information 440 indicative of operational status of selected portions of the well construction system 100 and software controls 430 for controlling selected portions of the well construction system 100, respectively. Each display screen may integrate the software controls 430 and/or sensor information 440 from one or more pieces of wellsite equipment (e.g., subsystems 211-217) with information generated by the control system 200 (e.g., the monitoring process 274, the control process 275, and the control data 261-267, 273) for viewing and/or operating by the wellsite operator 195. The display screens may be shown or displayed alternately on one or more of the video output devices 426 and/or the touchscreens 422, 424 or simultaneously on one or more of these devices. The display screens intended to be displayed on the video output devices 426 and/or the touchscreens 422, 424 may be selected by the wellsite operator 195 via the physical controls 414, 416, 418 and/or software controls 430. The display screens intended to be displayed on the video output devices 426 and/or the touchscreens 422, 424 may also or instead be selected automatically by the control system 200 based on operational events detected (e.g., equipment failures, hazardous drilling conditions) or planned (e.g., changing phases or stages of the well construction operations) at the well construction system 100, such that information relevant to the event currently taking place is displayed. Each display screen generated by the touchscreens 422, 424 may display software controls 430 operable by the wellsite operator 195 to control the wellsite equipment associated with the software controls 430, and each display screen generated by the video output devices 426 may display information 440 indicative of operational status of the wellsite equipment associated with the information 440. Accordingly, the display screens displayed on the touchscreens 422, 424 may be referred to hereinafter as control screens, and the display screens displayed on the video output devices 426 may be referred to hereinafter as status screens.

The video output devices 426 may be operable to alternatingly display a plurality of status screens. Some of the status screens may display operational status of a well construction operation (e.g., tripping, drilling, tubular handling, etc.) involving a plurality of pieces of wellsite equipment operating in a coordinated manner to perform such operation, which may permit the wellsite operator 195 to monitor operational status or parameters of such operation on a single status screen. Some of the status screens may display operational status of a single piece of wellsite equipment or a subsystem (e.g., subsystem 211-217) of wellsite equipment, such as may permit the wellsite operator 195 to monitor operational status or parameters of a single piece of equipment or an equipment subsystem. As described above, the status screen and the corresponding operation, wellsite equipment, or equipment subsystem may be selected via the touchscreens 422, 424. The status screens that may be selected for display may include a tripping status screen displaying information indicative of operational status of the tripping operations, a drilling status screen displaying information indicative of operational status of the drilling operations, a tubular handing status screen displaying information indicative of operational status of the tubular handling operations, and a plurality of subsystem status screens each displaying information indicative of operational status of the corresponding subsystem of the well construction system 100. The status screens within the scope of the present disclosure may also or instead display information indicative of operational status of individual pieces of wellsite equipment described herein.

The touchscreens 422, 424 may be operable to alternatingly display a plurality of control screens (e.g., configuration screens) each displaying corresponding software controls 430, which may be operated by the wellsite operator 195 to set, adjust, configure, operate, or otherwise control individual pieces of wellsite equipment and/or equipment subsystems (e.g., subsystems 211-217) of the well construction system 100 via finger contact with the touchscreens 422, 424 from the operator chair 402. FIGS. 7-9 are example implementations of software controls 452, 454, 456 that may be displayed on the touchscreens 422, 424 and operated by the wellsite operator 195 to control the individual equipment or equipment subsystems. The following description refers to FIGS. 6-9, collectively.

The software controls 452, 454, 456 may be pressed, clicked, selected, moved, or otherwise operated via the physical controls 414, 416 and/or via finger contact by the wellsite operator 195 to increase, decrease, change, or otherwise enter operational parameters, set-points, and/or instructions for controlling one or more pieces of wellsite equipment of the well construction system 100. The software controls 452, 454, 456 may also display the entered and/or current operational parameters on or in association with the software controls 452, 454, 456 for viewing by the wellsite operator 195. The operational parameters, set-points, and/or instructions associated with the software controls 452, 454, 456 may include equipment operational status (e.g., on or off, up or down, set or release, position, speed, temperature, etc.), drilling parameters (e.g., depth, hook load, torque, etc.), auxiliary parameters (e.g., vibration data of a pump), and fluid parameters (e.g., flow rate, pressure, temperature, etc.), among other examples.

The software controls 452 may be or comprise software buttons, which may be operated to increase, decrease, change, or otherwise enter different operational parameters, set-points, and/or instructions for controlling one or more portions of the well construction system 100 associated with the software controls 452. The software controls 454 may be or comprise a list or menu of items (e.g., equipment, processes, operational stages, equipment subsystems, etc.) related to one or more aspects of the well construction system 100, which may be operated to select one or more items on the list. The selected items may be highlighted, differently colored, or otherwise indicated, such as via a checkmark, a circle, or a dot appearing in association with the selected items. The software controls 456 may be or comprise a combination of different software controls, which may be operated to increase, decrease, change, or otherwise enter different operational parameters, set-points, and/or instructions for controlling one or more portions of the well construction system 100 associated with the software controls 456, such as a pump of the well construction system 100. The software controls 456 may include a slider 453, which may be moved or otherwise operated along a graduated bar to increase, decrease, or otherwise change pump speed or another operational parameter associated with the slider bar 453. The entered pump speed may be shown in a display window 455. The software controls 456 may also include software buttons 457, such as may be operated to start, pause, and stop operation of the pump or another portion of the well construction system 100 associated with the software buttons 457.

The present disclosure is further directed to communicatively connecting selected portions of fluid control equipment of the well construction system 100 with the workstation 197 via a data communication hub. FIG. 10 is a schematic view of at least a portion of an example implementation of a control system 500 according to one or more aspects of the present disclosure for monitoring and controlling equipment of the well construction system 100 shown in FIG. 1. The control system 500 may comprise one or more features of the control system 200 shown in FIGS. 2 and 3, including where indicated by the same reference numbers.

Accordingly, the following description refers to FIGS. 1-3 and 10, collectively.

The THR system 211 and perhaps other wellsite equipment (e.g., the FGM system 214, the CCTV system 215) of the well construction system 100 may be communicatively connected with the processing device 192 of the control workstation 197 via a data bus or network 502 (e.g., rig control network). Selected portions of fluid control equipment, such as the FP system 212, the MPDC system 213, the CPC system 216, and/or the WC system 217 of the well construction system 100 may be communicatively connected with the processing device 192 of the control workstation 197 via a data communication hub 504 communicatively connected between the processing device 192 and the selected portions of the subsystems 212, 213, 216, 217. The data communication hub 504 may be communicatively connected with the network 502 and with the selected portions of the subsystems 212, 213, 216, 217 via corresponding communication networks, data buses, cables, conductors, or other communication means 506. For example, the data communication hub 504 may be communicatively connected with the liquid gas separator 171 of the FP system 212, the RCD 138 and the choke manifold 152 of the MPDC system 213, the choke manifold 156 of the CPC system 216, and the BOP equipment 130, 132 of the WC system 217, among other examples.

The data communication hub 504 may be or comprise a local controller operable to monitor and control processes or operations of the subsystems 212, 213, 216, 217. The data communication hub 504 may comprise a processing device operable to receive sensor signals or information from the subsystems 212, 213, 216, 217, receive control commands from the control workstation 197, process the received information, and output control commands to actuators of the subsystems 212, 213, 216, 217 and status information to the control workstation. The processing device of the data communication hub 504 may include a PLC, an IPC, a PC, a soft PLC, and/or another controller or processing device operable to store execute machine-readable and executable program code instructions (i.e., computer program code) in a memory device of the processing device. The program code instructions, which when executed by the processing device, may cause or otherwise implement processes or operations performed by the subsystems 212, 213, 216, 217.

The data communication hub 504 may be operable to receive sensor signals or information 252, 253, 256, 257 from the selected equipment of the subsystems 212, 213, 216, 217 and translate or otherwise convert such sensor signals or information 252, 253, 256, 257 to a predetermined communication protocol (e.g., Modbus, Profinet, etc.) to be transmitted to the control workstation 197 via the network 502, which utilizes the predetermined communication protocol. For example, the data communication hub 504 may be operable to receive the sensor signals or information 252, 253, 256, 257 from the selected wellsite equipment via the communication means 506, translate such signals or information 252, 253, 256, 257 using the predetermined communication protocol, and transmit the translated signals or information 252, 253, 256, 257 via the network 502 to the control workstation 197, which may receive the translated signals or information 252, 253, 256, 257 from the data communication hub 504. The sensor signals or information 252, 253, 256, 257 received by the data communication hub 504 from the selected wellsite equipment may be in the form of analog signals, digital signals, and/or utilize another communication protocol. The wellsite equipment of the THR system 211 may be operable to transmit corresponding signals or information 251 to the workstation 197 via the network 502 using the predetermined communication protocol without utilizing the data communication hub 504 or another communication device communicatively connected between the workstation 197 and the THR system 211 to translate the signals or information 251 before being transmitted to the workstation 197 via the network 502. The control workstation 197 may process the received sensor signals or information 252, 253, 256, 257 and then transmit control commands 262, 263, 266, 267 using the predetermined communication protocol via the network 502 to the data communication hub 504, which may receive and transmit such control commands 262, 263, 266, 267 to the corresponding wellsite equipment of the subsystems 212, 213, 216, 217, perhaps in the form of analog signals, digital signals, and/or another communication protocol utilized by such wellsite equipment. The control workstation 197 may also process the received sensor signals or information 251 and then transmit control commands 261 using the predetermined communication protocol via the network 502 to the corresponding wellsite equipment of the THR system 211.

FIG. 11 is a schematic view of a portion of an example implementation of a control system 600 according to one or more aspects of the present disclosure for monitoring and controlling selected wellsite equipment of the well construction system 100 shown in FIG. 1. The control system 600 may be or comprise a portion of an example implementation of the control system 500 shown in FIG. 10 and, thus, may comprise one or more features of the control system 500. Communicative and/or electrical connections, such as cables and other conductors, are indicated in FIG. 11 by dashed lines. However, it is to be understood that one or more of the communicative connections shown in FIG. 11 may be implemented via wireless communication means and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure. The following description refers to FIGS. 1-3, 10, and 11, collectively.

The control system 600 may comprise a data communication hub 602 communicatively connected between the control workstation 197 and corresponding sensors and/or actuators of selected wellsite equipment 604, 606, 608. The data communication hub 602 may be communicatively connected with the control workstation 197 via one or more cables or other conductors 616. The conductor 616 may form a portion of the communication network 502 or be communicatively connected with the communication network 502. The data communication hub 602 may be electrically connected with and powered via an uninterruptable power supply (UPS) 610 that may operate on standard input power of 110 VAC. The UPS 610 may also be electrically connected with and provide power to one or more of the wellsite equipment 604, 606, 608 communicatively connected with the data communication hub 602. The data communication hub 602 and the UPS 610 may be installed within a cabinet or another enclosure 612 at the wellsite 104. The UPS 610 may be electrically connected with a source of electrical power (not shown) via one or more electrical conductors 614.

The data communication hub 602 may be or comprise a local controller operable to monitor and control processes or operations of the wellsite equipment 604, 606, 608. The data communication hub 602 may comprise a processing device 603 operable to receive sensor signals or information from the wellsite equipment 604, 606, 608, receive control commands from the control workstation 197, process the received information, and output control commands to actuators of the wellsite equipment 604, 606, 608 and status information to the control workstation. The processing device 603 may include a PLC, an IPC, a PC, a soft PLC, and/or another controller or processing device operable to store execute machine-readable and executable program code instructions (i.e., computer program code) in a memory device of the processing device. The program code instructions, which when executed by the processing device 603, may cause or otherwise implement processes or operations performed by the wellsite equipment 604, 606, 608.

The data communication hub 602 may be communicatively connected with a choke manifold 604 of the CPC system 216 and/or the MPDC system 213, such as may permit the control workstation 197 to monitor and/or control one or more portions of the choke manifold 604. For example, the data communication hub 602 may be communicatively connected with electrical actuators 618 operatively connected with actuated or movable portions (e.g., stems) of choke valves 620 of the choke manifold 604, such as may permit choke control from the control workstation 197. Each actuator 618 may be operable to progressively open and close the corresponding choke valve 620, such as via an electric servomotor driving a gearbox connected to a disc choke bonnet shaft to turn an orifice disc plate of the choke valve 620. A position sensor 621 (e.g., a limit switch) may be installed in association with each actuator 618 to generate signals or information indicative of choke position. Pressure sensors 624 operable to generate signals or information indicative of choke pressure may be mounted within the choke manifold 604 upstream and/or downstream from the choke valves 620. The actuators 618, the pressure sensors 624, and the position sensors 621 may be communicatively connected with local actuator drives 626 (e.g., drive boxes), which may be operable to receive and/or process the signals or information from the pressure sensors 624 and the position sensors 621, and locally drive the actuators 618 based on the received signals or information. The local drive boxes 626 may be communicatively connected with the processing device 603 of the data communication hub 602 via one or more multi-wired electrical cables or conductors 627, such as may facilitate signal communication between the actuators 618, pressure sensors 624, and position sensors 621 and the control workstation 197 and, thus, facilitate control of the actuators 618 by the processing device 603 and/or the control workstation 197, such as based on the signals or information from the pressure sensors 624 and position sensors 621. An electrical tee adapter 628 may be connected between the local drives 626 and the data communication hub 602, such as to reduce the quantity of the multi-wired cables or conductors 627 connecting with the data communication hub 602. The local drives 626 may be electrically connected with the UPS 610 to provide electrical power to the local drives 626, the actuators 618, the pressure sensors 624, and/or the position sensors 621. The choke manifold 604 may be an example implementation of the choke manifold 156 shown in FIG. 1.

The data communication hub 602 may be communicatively connected with a liquid gas separator 606 of the FP system 212 such as may permit the control workstation 197 to monitor operation of the liquid gas separator 606. For example, the data communication hub 602 may be communicatively connected with pressure sensors 630, liquid level sensors 632, a temperature sensor 634, and an alarm horn 635 operatively connected at selected locations along a liquid gas separator vessel 636, facilitating monitoring of pressure and liquid level within different portions of the liquid gas separator vessel 636, monitoring of temperature within a liquid seal of the liquid gas separator vessel 636, and operating of the alarm horn 635. The pressure sensors 630, the liquid level sensors 632, the temperature sensor 634, and the alarm horn 635 may be communicatively connected with a drive/junction box 638, which may be operable to receive and/or process the signals or information from the sensors 630, 632, 634, supply electrical power to the sensors 630, 632, 634, and perhaps display such signal or information to a wellsite operator 195 and/or locally activate the alarm horn 635 based on the received signals or information. The drive/junction box 638 may be communicatively connected with the data communication hub 602 via one or more multi-wired electrical cables or conductors 639, such as may facilitate signal communication between the sensors 630, 632, 634 and alarm horn 635 and the control workstation 197, thereby permitting the control workstation 197 to monitor operational status of the liquid gas separator vessel 636 and activate the alarm horn 635 based on the received signals or information from the sensors 630, 632, 634. The liquid gas separator 606 may be an example implementation of the liquid gas separator 171 shown in FIG. 1.

The data communication hub 602 may be communicatively connected with a gas tracker 608 (e.g., carbon tracker) of the FP system 212, such as may permit the control workstation 197 to monitor separated gas that is discharged from the liquid gas separator vessel 636. The gas tracker 608 may comprise a conduit portion 640 coupled along a flare line 642 between gas exhaust port 644 of the liquid gas separator vessel 636 and the flare stack 174. The conduit portion 640 may carry a plurality of sensors operable to measure the separated gas passing through the conduit portion 640. Such sensors may include ultrasonic flow rate sensors 646 for measuring gas flow velocity and volumetric and/or mass gas flow rates, a pressure sensor 648, and a temperature sensor 650. The pressure and temperature measurements may be utilized to determine the volumetric and/or mass gas flow rates. The sensors 646, 648, 650 may be communicatively connected with a drive/junction box 652, which may be operable to receive and/or process the signals or information from the sensors 646, 648, 650 supply electrical power to the sensors 646, 648, 650, and perhaps display such signal or information to a wellsite operator 195. The drive/junction box 652 may be communicatively connected with the data communication hub 602 via one or more multi-wired electrical cables or conductors 653, such as may facilitate signal communication between the sensors 646, 648, 650 and the control workstation 197, thereby permitting the control workstation 197 to monitor the separated gasses being transferred from the liquid gas separator vessel 636 to the flare stack 174. The gas tracker 608 may be an example implementation of the gas sensor 176 shown in FIG. 1.

The data communication hub 602 may be operable to translate or otherwise convert the signals or information communicated between the wellsite equipment 604, 606, 608 and the control workstation 197 to corresponding communication protocols to permit the wellsite equipment 604, 606, 608 and the control workstation 197 to communicate with each other via the network 502. The data communication hub 602 may be further operable to reduce the quantity of cables or conductors communicatively connecting the wellsite equipment 604, 606, 608 with the control workstation 197. As shown in FIG. 11 and described above, the data communication hub 602 may be communicatively connected with the selected wellsite equipment 604, 606, 608 via a plurality (e.g., four) of corresponding multi-conductor cables 627, 639, 653. The data communication hub 602 may be communicatively connected with the control workstation 197 and/or the network 502 via a single multi-conductor cable or conductor 616 or an otherwise reduced number (e.g., two or three) of multi-conductor cables or conductors. Accordingly, the data communication hub 602 may be operable to receive sensor signals or information from the selected wellsite equipment 602, 606, 608 and transmit control commands to such wellsite equipment 602, 606, 608 via the multi-conductor cables or conductors 627, 639, 653, and transmit the sensor signals or information to the control workstation 197 and receive control commands from the control workstation 197 via one or otherwise reduced number of multi-conductor cables or conductors 616.

FIG. 12 is a schematic view of a portion of an example implementation of a control system 700 according to one or more aspects of the present disclosure for monitoring and controlling selected wellsite equipment of the well construction system 100 shown in FIG. 1. The control system 700 may comprise one or more features of the control system 600, shown in FIG. 11, including where indicated by the same reference numbers. Accordingly, the following description refers to FIGS. 1, 11, and 12, collectively.

The control system 700 may comprise a choke manifold 604 having a fluid inlet 702, which may be fluidly coupled with the conduit 154 for receiving the drilling fluid from the wellbore annulus 108. The control system 700 may further comprise a liquid gas separator 606 comprising a liquid gas separator vessel 636 having a fluid inlet 704 fluidly coupled with an outlet 706 of the choke manifold 604. The liquid gas separator vessel 636 may receive the drilling fluid from the choke manifold 604 and separate the drilling fluid into liquid and gas. The liquid may be discharged from the liquid gas separator vessel 636 via a liquid outlet 708 for transfer to subsequent fluid reconditioning equipment 170. The gas may be discharged from the liquid gas separator vessel 636 via a gas outlet 644 for transfer to the flare stack 174 via a flare line 642. The control system 700 may also comprise a gas tracker 608 coupled along the flare line 642 for monitoring the gasses separated and discharged by the liquid gas separator vessel 636. The control system 700 may also comprise a data communication hub 602 communicatively connected with various sensors 624, 630, 632, 634, 646, 648, 650 and actuators 618 of the wellsite equipment 604, 606, 608 via corresponding cables or conductors 627, 639, 653 and perhaps corresponding drives/junction boxes 626, 638, 652. The data communication hub 602 may be directly or indirectly communicatively connected with the control workstation 197, such as via a cable or conductor 616. The data communication hub 602 may be electrically connected with and powered via a UPS 610 which, in turn, may be electrically connected with a source of electrical power (not shown), such as via an electrical cable or conductor 614. The data communication hub 602 and the UPS 610 may be installed within a cabinet or another enclosure 612.

The control system 700 may be skidded. For example, the wellsite equipment 604, 606, 608, the UPS 610, and the data communication hub 602 may be mounted or otherwise fixedly connected to a common skid 720, such that the wellsite equipment 604, 606, 608, the UPS 610, and the data communication hub 602 may be moved to and about a wellsite 104 as a single unit. If the control system 700 comprises the enclosure 612 containing the data communication hub 602, the enclosure 612 may be fixedly connected to the skid 720. The skid may be or comprise a steel frame on which the equipment 602, 604, 606, 608, 610 may be mounted, such as to facilitate handling with cranes or flatbed trucks. The skid 720 may be robust and comprise attachment points 722 for hooks, chains, or cables. The skid 720 may comprise two or more lengthwise beams (not shown), which may permit the skid 720 to be slid into place at the wellsite 104. After the control system 700 is positioned at an intended location at the wellsite 104, the conduit 154 may be coupled with the inlet 702 of the choke manifold 604, the liquid outlet 708 of the liquid gas separator vessel 636 may be coupled with other fluid reconditioning equipment 170, the gas tracker 608 may be connected with a portion of the flare line 642 extending to the flare stack 174, the UPS 610 may be connected with a source of electrical power (not shown), and the data communication hub 602 may be communicatively connected with the network 502 or otherwise with the control workstation 197.

FIG. 13 is a schematic view of a portion of an example implementation of a control system 800 according to one or more aspects of the present disclosure for monitoring and controlling selected wellsite equipment of the well construction system 100 shown in FIG. 1. The control system 800 may comprise features of the control system 600 shown in FIG. 11, including where indicated by the same reference numbers. Communicative and/or electrical connections, such as cables and other conductors, are indicated in FIG. 13 by dashed lines. However, it is to be understood that one or more of the communicative connections of the control system 800 may be implemented via wireless communication means and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure. The following description refers to FIGS. 1, 11, and 13, collectively.

The control system 800 may comprise a data communication hub 802 communicatively connected between the control workstation 197 and corresponding sensors and/or actuators of selected wellsite equipment 804, 806, 808. The data communication hub 802 may be communicatively connected with the control workstation 197 via one or more cables or other conductors 616. The data communication hub 802 may be electrically connected with and powered via an uninterruptable power supply (UPS) 610 that may operate on standard input power of 110 VAC. The UPS 610 may also be electrically connected with and provide power to one or more of the wellsite equipment 804, 806, 808 communicatively connected with the data communication hub 802. The data communication hub 802 and the UPS 610 may be installed within a cabinet or another enclosure 612 at the wellsite 104. The UPS 610 may be electrically connected with a source of electrical power (not shown) via one or more electrical conductors 614.

The data communication hub 802 may be or comprise a local controller operable to monitor and control processes or operations of the wellsite equipment 804, 806, 808. The data communication hub 802 may comprise a processing device 803 operable to receive sensor signals or information from the wellsite equipment 804, 806, 808, receive control commands from the control workstation 197, process the received information, and output control commands to actuators of the wellsite equipment 804, 806, 808 and status information to the control workstation. The processing device 803 may include a PLC, an IPC, a PC, a soft PLC, and/or another controller or processing device operable to store execute machine-readable and executable program code instructions (i.e., computer program code) in a memory device of the processing device. The program code instructions, which when executed by the processing device 803, may cause or otherwise implement processes or operations performed by the wellsite equipment 804, 806, 808.

The data communication hub 802 may be communicatively connected with a choke manifold 804 of the CPC system 216 and/or the MPDC system 213, such as may permit the control workstation 197 to monitor and/or control one or more portions of the choke manifold 804. For example, the data communication hub 802 may be communicatively connected with electrical actuators 618 operatively connected with actuated or movable portions (e.g., stems) of choke valves 620 of the choke manifold 804, such as may permit choke control from the control workstation 197. Each actuator 618 may be operable to progressively open and close the corresponding choke valve 620, such as via an electric servomotor driving a gearbox connected to a disc choke bonnet shaft to turn an orifice disc plate of the choke valve 620. A position sensor 621 (e.g., a limit switch) may be installed in association with each actuator 618 to generate signals or information indicative of choke position. Pressure sensors 624 operable to generate signals or information indicative of choke pressure may be mounted within the choke manifold 804 upstream and/or downstream from the choke valves 620. The actuators 618, the pressure sensors 624, and the position sensors 621 may be communicatively connected directly with the data communication hub 802 via one or more multi-wired electrical cables or conductors 827, such as may permit the data communication hub 802 to receive and/or process the signals or information from the pressure sensors 624 and the position sensors 621, and transmit control signals (e.g., electrical power) to the actuators 618 based on the received signals or information. The data communication hub 802 may comprise one or more actuator drives 826 (e.g., VFDs) communicatively connected with the processing device 803 and one or more of the electrical power to the actuators 618, the pressure sensors 624, and/or the position sensors 621 via the electrical conductors 827. The drives 826 may be operable to drive the actuators 618 based on control commands from the processing device 803. The drives 826 may be electrically connected with the UPS 610, the actuators 618, the pressure sensors 624, and/or the position sensors 621 and operable to supply electrical power to the actuators 618, the pressure sensors 624, and/or the position sensors 621. The choke manifold 804 may be an example implementation of the choke manifold 156 shown in FIG. 1.

The data communication hub 802 may be communicatively connected with a liquid gas separator 806 of the FP system 212 such as may permit the control workstation 197 to monitor operation of the liquid gas separator 806. For example, the data communication hub 802 may be communicatively connected with pressure sensors 630, liquid level sensors 632, a temperature sensor 634, and an alarm horn 635 operatively connected at selected locations along a liquid gas separator vessel 636, facilitating monitoring of pressure and liquid level within different portions of the liquid gas separator vessel 636, monitoring of temperature within a liquid seal of the liquid gas separator vessel 636, and operating of the alarm horn 635. The pressure sensors 630, the liquid level sensors 632, the temperature sensor 634, and the alarm horn 635 may be communicatively connected directly with the data communication hub 802 via one or more multi-wired electrical cables or conductors 839. The conductors 839 may be communicatively connected with the data communication hub 802 via an electrical junction 838 (e.g., a junction box) of the data communication hub 802. The electrical junction 838 may be operable to receive and/or process the signals or information from the sensors 630, 632, 634, supply electrical power to the sensors 630, 632, 634, and perhaps display such signal or information to a wellsite operator 195 and/or locally activate the alarm horn 635 based on the received signals or information. The data communication hub 802 may facilitate signal communication between the sensors 630, 632, 634 and alarm horn 635 and the control workstation 197, thereby permitting the control workstation 197 to monitor operational status of the liquid gas separator vessel 636 and activate the alarm horn 635 based on the received signals or information from the sensors 630, 632, 634. The liquid gas separator 806 may be an example implementation of the liquid gas separator 171 shown in FIG. 1.

The data communication hub 802 may be communicatively connected with a gas tracker 808 (e.g., carbon tracker) of the FP system 212, such as may permit the control workstation 197 to monitor separated gas that is discharged from the liquid gas separator vessel 636. The gas tracker 808 may comprise a conduit portion 640 coupled along a flare line 642 between gas exhaust port 644 of the liquid gas separator vessel 636 and the flare stack 174. The conduit portion 640 may carry a plurality of sensors operable to measure the separated gas passing through the conduit portion 640. Such sensors may include ultrasonic flow rate sensors 646 for measuring gas flow velocity and volumetric and/or mass gas flow rates, a pressure sensor 648, and a temperature sensor 650. The pressure and temperature measurements may be utilized to determine the volumetric and/or mass gas flow rates. The sensors 646, 648, 650 may be communicatively connected directly with the data communication hub 802 via one or more multi-wired electrical cables or conductors 853. The conductors 853 may be communicatively connected with the data communication hub 802 via a drive/electrical junction 852 of the data communication hub 802. The drive/electrical junction 852 may be operable to receive and/or process the signals or information from the sensors 646, 648, 650, supply electrical power to the sensors 646, 648, 650, and perhaps display such signal or information to a wellsite operator 195. The data communication hub 802 may facilitate signal communication between the sensors 646, 648, 650 and the control workstation 197, thereby permitting the control workstation 197 to monitor the separated gasses being transferred from the liquid gas separator vessel 636 to the flare stack 174. The gas tracker 808 may be an example implementation of the gas sensor 176 shown in FIG. 1.

The data communication hub 802 may be operable to translate or otherwise convert the signals or information communicated between the wellsite equipment 804, 806, 808 and the control workstation 197 to corresponding communication protocols to permit the wellsite equipment 804, 806, 808 and the control workstation 197 to communicate with each other via the network 502. The data communication hub 802 may be further operable to reduce the quantity of cables or conductors communicatively connecting the wellsite equipment 804, 806, 808 with the control workstation 197. As shown in FIG. 13 and described above, the data communication hub 802 may be communicatively connected with the selected wellsite equipment 804, 806, 808 via a plurality (e.g., three) of corresponding multi-conductor cables 827, 839, 853. The data communication hub 802 may be communicatively connected with the control workstation 197 and/or the network 502 via a single multi-conductor cable or conductor 616 or an otherwise reduced number (e.g., two or three) of multi-conductor cables or conductors. Accordingly, the data communication hub 802 may be operable to receive sensor signals or information from the selected wellsite equipment 802, 806, 808 and transmit control commands to such wellsite equipment 802, 806, 808 via the multi-conductor cables or conductors 827, 839, 853, and transmit the sensor signals or information to the control workstation 197 and receive control commands from the control workstation 197 via one or otherwise reduced number of multi-conductor cables or conductors 616.

FIG. 14 is a schematic view of a portion of an example implementation of a control system 900 according to one or more aspects of the present disclosure for monitoring and controlling selected wellsite equipment of the well construction system 100 shown in FIG. 1. The control system 900 may comprise one or more features of the control systems 700, 800, shown in FIGS. 12 and 13, respectively, including where indicated by the same reference numbers. Accordingly, the following description refers to FIGS. 1, 12, 13, and 14, collectively.

The control system 900 may comprise a choke manifold 804 having a fluid inlet 702, which may be fluidly coupled with the conduit 154 for receiving the drilling fluid from the wellbore annulus 108. The control system 900 may further comprise a liquid gas separator 806 comprising a liquid gas separator vessel 636 having a fluid inlet 704 fluidly coupled with an outlet 706 of the choke manifold 804. The liquid gas separator vessel 636 may receive the drilling fluid from the choke manifold 804 and separate the drilling fluid into liquid and gas. The liquid may be discharged from the liquid gas separator vessel 636 via a liquid outlet 708 for transfer to subsequent fluid reconditioning equipment 170. The gas may be discharged from the liquid gas separator vessel 636 via a gas outlet 644 for transfer to the flare stack 174 via a flare line 642. The control system 800 may also comprise a gas tracker 808 coupled along the flare line 642 for monitoring the gasses separated and discharged by the liquid gas separator vessel 636. The control system 800 may also comprise a data communication hub 802 communicatively connected with various sensors 624, 630, 632, 634, 646, 648, 650 and actuators 618 of the wellsite equipment 804, 806, 808 via corresponding cables or conductors 827, 839, 853. The data communication hub 802 may comprise actuator drives and/or electrical junctions 826, 838, 852, which may be utilized to communicatively connect the sensors 624, 630, 632, 634, 646, 648, 650 and actuators 618 of the wellsite equipment 804, 806, 808 with a processing device 803 of the data communication hub 802. The data communication hub 802 may be directly or indirectly communicatively connected with the control workstation 197, such as via a cable or conductor 616. The data communication hub 802 may be electrically connected with and powered via a UPS 610 which, in turn, may be electrically connected with a source of electrical power (not shown), such as via an electrical cable or conductor 614. The data communication hub 802 and the UPS 610 may be installed within a cabinet or another enclosure 612.

The control system 900 may be skidded. For example, the wellsite equipment 804, 806, 808, the UPS 610, and the data communication hub 802 may be mounted or otherwise fixedly connected to a common skid 720, such that the wellsite equipment 804, 806, 808, the UPS 610, and the data communication hub 802 may be moved to and about a wellsite 104 as a single unit. If the control system 900 comprises the enclosure 612 containing the data communication hub 802, the enclosure 612 may be fixedly connected to the skid 720. The skid may be or comprise a steel frame on which the equipment 802, 804, 806, 808, 610 may be mounted, such as to facilitate handling with cranes or flatbed trucks. The skid 720 may be robust and comprise attachment points 722 for hooks, chains, or cables. The skid 720 may comprise two or more lengthwise beams (not shown), which may permit the skid 720 to be slid into place at the wellsite 104. After the control system 900 is positioned at an intended location at the wellsite 104, the conduit 154 may be coupled with the inlet 702 of the choke manifold 804, the liquid outlet 708 of the liquid gas separator vessel 636 may be coupled with other fluid reconditioning equipment 170, the gas tracker 808 may be connected with a portion of the flare line 642 extending to the flare stack 174, the UPS 610 may be connected with a source of electrical power (not shown), and the data communication hub 802 may be communicatively connected with the network 502 or otherwise with the control workstation 197.

FIG. 15 is a schematic view of at least a portion of an example implementation of a processing device 1000 according to one or more aspects of the present disclosure. The processing device 1000 may form at least a portion of one or more electronic devices utilized at the well construction system 100 and shown in one or more FIGS. 1-14. For example, the processing device 1000 may be or form at least a portion of the processing devices 192 and the control workstations 197, 350, 352, 354, 400. The processing device 1000 may form at least a portion of the control system 200, including the wellsite computing resource environment 205, the coordinated control device 204, the supervisory control system 207, the local controllers 241-247, the onsite user devices 202, and the offsite user devices 203. The processing device 1000 may form at least a portion of the data communication hub 504. The processing device 1000 may also form at least a portion of the data communication hub 602, including the processing device 603. The processing device 1000 may form at least a portion of the data communication hub 802, including the processing device 803, the actuator drives 826, and the electrical junctions 638, 652, 838, 852.

The processing device 1000 may be in communication with various sensors, actuators, controllers, and other devices of the subsystems 211-217 and/or other portions of the well construction system 100. The processing device 1000 may be operable to receive coded instructions 1032 from the wellsite operators 195 via the wellsite control workstation 197 and the sensor data 251-257 generated by the sensors 221-227, 624, 630, 632, 634, 646, 648, 650, process the coded instructions 1032 and the sensor data 251-257, and communicate the control data 261-267 to the local controllers 241-247, data communication hubs 602, 802, and/or the actuators 231-237, 618 of the subsystems 211-217 to execute the coded instructions 1032 to implement at least a portion of one or more example methods and/or operations described herein, and/or to implement at least a portion of one or more of the example systems described herein.

The processing device 1000 may be or comprise, for example, one or more processors, special-purpose computing devices, servers, personal computers (e.g., desktop, laptop, and/or tablet computers), personal digital assistants, smartphones, internet appliances, and/or other types of computing devices. The processing device 1000 may comprise a processor 1012, such as a general-purpose programmable processor. The processor 1012 may comprise a local memory 1014, and may execute coded instructions 1032 present in the local memory 1014 and/or another memory device. The processor 1012 may execute, among other things, the machine-readable coded instructions 1032 and/or other instructions and/or programs to implement the example methods and/or operations described herein. The programs stored in the local memory 1014 may include program instructions or computer program code that, when executed by the processor 1012 of the processing device 1000, may cause the subsystems 211-217 and/or individual pieces of wellsite equipment 604, 606, 608, 804, 806, 808 of the well construction system 100 to perform the example methods and/or operations described herein. The processor 1012 may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples. Of course, other processors from other families are also appropriate.

The processor 1012 may be in communication with a main memory 1016, such as may include a volatile memory 1018 and a non-volatile memory 1020, perhaps via a bus 1022 and/or other communication means. The volatile memory 1018 may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices. The non-volatile memory 1020 may be, comprise, or be implemented by read-only memory, flash memory, and/or other types of memory devices. One or more memory controllers (not shown) may control access to the volatile memory 1018 and/or non-volatile memory 1020.

The processing device 1000 may also comprise an interface circuit 1024. The interface circuit 1024 may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others. The interface circuit 1024 may also comprise a graphics driver card. The interface circuit 1024 may also comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.). One or more of the local controllers 241-247, data communication hubs 602, 802, the sensors 221-227, 624, 630, 632, 634, 646, 648, 650, and the actuators 231-237, 618 may be connected with the processing device 1000 via the interface circuit 1024, such as may facilitate communication between the processing device 1000 and the local controllers 241-247, data communication hubs 602, 802, the sensors 221-227, 624, 630, 632, 634, 646, 648, 650, and/or the actuators 231-237, 618.

One or more input devices 1026 may also be connected to the interface circuit 1024. The input devices 1026 may permit the wellsite operators 195 to enter the coded instructions 1032, such as control commands, operational settings and set-points, and/or processing routines, such as for translating sensor signals or information to a predetermined communication protocol signals or information. The input devices 1026 may be, comprise, or be implemented by a keyboard, a mouse, a joystick, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples. One or more output devices 1028 may also be connected to the interface circuit 1024. The output devices 1028 may be, comprise, or be implemented by video output devices (e.g., an LCD, an LED display, a CRT display, a touchscreen, etc.), printers, and/or speakers, among other examples. The processing device 1000 may also communicate with one or more mass storage devices 1030 and/or a removable storage medium 1034, such as may be or include floppy disk drives, hard drive disks, compact disk (CD) drives, digital versatile disk (DVD) drives, and/or USB and/or other flash drives, among other examples.

The coded instructions 1032 may be stored in the mass storage device 1030, the main memory 1016, the local memory 1014, and/or the removable storage medium 1034. Thus, the processing device 1000 may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor 1012. In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code (i.e., software or firmware) thereon for execution by the processor 1012. The coded instructions 1032 may include program instructions or computer program code that, when executed by the processor 1012, may cause the various subsystems 211-217 or individual pieces of wellsite equipment 604, 606, 608, 804, 806, 808 of the well construction system 100 to perform intended methods, processes, and/or operations disclosed herein.

In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising: a data communication hub communicatively connected with fluid control equipment of a well construction system for constructing a well at an oil/gas wellsite; and a control workstation communicatively connected with tubular handling and rotation equipment of the well construction system, wherein the control workstation is communicatively connected with the data communication hub, and wherein the control workstation is communicatively connected with the fluid control equipment via the data communication hub.

The fluid control equipment may comprise at least one of: a fluid processing system; a well control system; a managed pressure drilling control system; and a choke pressure control system. In such implementations, among others within the scope of the present disclosure, the tubular handling and rotation equipment may comprise at least one of: tubular handling equipment operable to move drill pipe at the oil/gas wellsite; drill string make up and brake out equipment operable to connect and disconnect drill pipe; drill string hoisting equipment operable to move a drill string within a wellbore; and drill string rotation equipment operable to rotate the drill string within the wellbore.

The fluid control equipment may comprise: a choke manifold; a liquid gas separator; and a gas sensor.

The fluid control equipment and the data communication hub may be connected to a common frame, and the fluid control equipment, the data communication hub, and the common frame may form at least a portion of an equipment skid movable as a single unit. In such implementations, among others within the scope of the present disclosure, the fluid control equipment may comprise a choke manifold and a liquid gas separator, and the liquid gas separator may be configured to receive fluid passing through the choke manifold.

The control workstation may comprise or be communicatively connected with a processor and a memory storing an executable computer program code.

The workstation may comprise: a chair for a human wellsite operator; input devices disposed in association with the chair and operable for entering control commands for controlling the fluid control equipment and the tubular handling and rotation equipment by the human wellsite operator; and a video output device disposed in association with the chair and operable to display information indicative of operational status of the fluid control equipment and the tubular handling and rotation equipment.

The data communication hub may comprise a processing device and a memory storing an executable computer program code. In such implementations, among others within the scope of the present disclosure, the data communication hub may comprise: an actuator drive communicatively connected with the processing device and electrically connected with an electrical actuator disposed in association with or forming at least a portion of the fluid control equipment; and an electrical junction communicatively connected with the processing device and electrically connecting the data communication hub with a plurality of sensors disposed in association with or forming at least a portion of the fluid control equipment.

The data communication hub may be communicatively connected with the fluid control equipment via a plurality of multi-conductor cables each connected with a corresponding piece of the fluid control equipment, the data communication hub may be communicatively connected with the control workstation via a single multi-conductor cable, and the data communication hub may be operable to: receive first information from the fluid control equipment via the plurality of multi-conductor cables; and transmit the first information to the control workstation via the single multi-conductor cable.

The data communication hub may be operable to: receive information from the fluid control equipment; and convert the information to a communication protocol signal for reception by the control workstation.

The data communication hub may be operable to receive first information using a first communication protocol from the fluid control equipment, and to transmit the first information using a second communication protocol to the control workstation, and the control workstation may be operable to receive the first information using the second communication protocol from the data communication hub, and to receive second information using the second communication protocol from the tubular handling and rotation equipment. The first information may be indicative of operational status of the fluid control equipment, and the second information may be indicative of operational status of the tubular handling and rotation equipment. In such implementations, among others within the scope of the present disclosure, the control workstation may be operable to transmit first control commands using the second communication protocol to the data communication hub, and to transmit second control commands using the second communication protocol to the tubular handling and rotation equipment, and the data communication hub may be operable to receive the first control commands using the second communication protocol, and to transmit the first control commands using the first communication protocol to the fluid control equipment. The control workstation may be operable to receive third control commands from a human wellsite operator, and the first and second control commands may be at least partially based on the third control commands. The control workstation may be further operable to generate the second control commands at least partially based on the first information. The control workstation may comprise a processor and a memory storing a computer program code, and the control workstation may be further operable to generate the second control commands at least partially based on the computer program code and the first information. The first information may be generated by first sensors disposed in association with or forming at least a portion of the fluid control equipment, the second information may be generated by second sensors disposed in association with or forming at least a portion of the tubular handling and rotation equipment, the first control commands may be transmitted to first actuators disposed in association with or forming at least a portion of the fluid control equipment, and the second control commands may be transmitted to second actuators disposed in association with or forming at least a portion of the tubular handling and rotation equipment.

The control workstation, the tubular handling and rotation equipment, and the data communication hub may be communicatively connected with a rig control communication network to communicatively connect the control workstation with the tubular handling and rotation equipment and the data communication hub.

The present disclosure also introduces an apparatus comprising: a control workstation for controlling a well construction system operable to construct a well at an oil/gas wellsite, wherein the control workstation is operable to receive from fluid control equipment of the well construction system first information indicative of operational status of the fluid control equipment, and to receive from tubular handling and rotation equipment of the well construction system second information indicative of operational status of the tubular handling and rotation equipment; and a data communication hub communicatively connected with the fluid control equipment via a plurality of first multi-conductor cables each connected with a corresponding piece of the fluid control equipment, wherein the data communication hub is communicatively connected with the control workstation via a second multi-conductor cable, and wherein the data communication hub is operable to receive first information from the fluid control equipment via the plurality of first multi-conductor cables, and to transmit the first information to the control workstation via the second multi-conductor cable.

The fluid control equipment may comprise at least one of a fluid processing system, a well control system, a managed pressure drilling control system, and a choke pressure control system, and the tubular handling and rotation equipment may comprise at least one of: tubular handling equipment operable to move drill pipe at the oil/gas wellsite; drill string make up and brake out equipment operable to connect and disconnect drill pipe; drill string hoisting equipment operable to move a drill string within a wellbore; and drill string rotation equipment operable to rotate the drill string within the wellbore.

The fluid control equipment may comprise at least one of: a choke manifold; a liquid gas separator; and a gas sensor.

The fluid control equipment and the data communication hub may be connected to a common frame, and the fluid control equipment, the data communication hub, and the common frame may form at least a portion of an equipment skid movable as a single unit. In such implementations, among others within the scope of the present disclosure, the fluid control equipment may comprise a choke manifold and a liquid gas separator, and the liquid gas separator may be configured to receive fluid passing through the choke manifold.

The control workstation may comprise or be communicatively connected with a processor and a memory storing an executable computer program code.

The workstation may comprise: a chair for a human wellsite operator; input devices disposed in association with the chair and operable for entering control commands for controlling the fluid control equipment and the tubular handling and rotation equipment by the human wellsite operator while sitting in the chair; and a video output device disposed in association with the chair and operable to display information indicative of operational status of the fluid control equipment and the tubular handling and rotation equipment.

The data communication hub may comprise a processing device and a memory storing an executable computer program code. In such implementations, among others within the scope of the present disclosure, the data communication hub may comprise: an actuator drive communicatively connected with the processing device and electrically connected with an electrical actuator disposed in association with or forming at least a portion of the fluid control equipment; and an electrical junction communicatively connected with the processing device and electrically connecting the data communication hub with a plurality of sensors disposed in association with or forming at least a portion of the fluid control equipment.

The second multi-conductor cable may be a single multi-conductor cable, and the data communication hub may be operable to transmit the first information to the control workstation via the single multi-conductor cable.

The data communication hub may be operable to convert the first information to a predetermined communication protocol signal for reception by the control workstation.

The data communication hub may be operable to transmit the first information using a predetermined communication protocol to the control workstation, the control workstation may be operable to receive the first information from the data communication hub, and the second information may be transmitted to the control workstation using the predetermined communication protocol. The control workstation may be operable to transmit first control commands using the predetermined communication protocol to the data communication hub, and to transmit second control commands using the predetermined communication protocol to the tubular handling and rotation equipment, and the data communication hub may be operable to receive the first control commands using the predetermined communication protocol from the control workstation, and to transmit the first control commands using another communication protocol to the fluid control equipment. The first information may be generated by first sensors disposed in association with or forming at least a portion of the fluid control equipment, the second information may be generated by second sensors disposed in association with or forming at least a portion of the tubular handling and rotation equipment, the first control commands may be transmitted to first actuators disposed in association with or forming at least a portion of the fluid control equipment, and the second control commands may be transmitted to second actuators disposed in association with or forming at least a portion of the tubular handling and rotation equipment.

The control workstation, the tubular handling and rotation equipment, and the data communication hub may be communicatively connected with a rig control communication network to communicatively connect the control workstation with the tubular handling and rotation equipment and the data communication hub.

The present disclosure also introduces a method comprising: operating a well construction system to construct a well at an oil/gas wellsite while generating first information indicative of operational status of fluid control equipment of the well construction system and generating second information indicative of operational status of tubular handling and rotation equipment of the well construction system; operating a data communication hub to receive the first information and transmit the first information using a predetermined communication protocol; and operating a control workstation for controlling the well construction system to receive the first information from the data communication hub and receive the second information from the tubular handling and rotation equipment.

The fluid control equipment may comprise at least one of a fluid processing system, a well control system, a managed pressure drilling control system, and a choke pressure control system, and the tubular handling and rotation equipment may comprise at least one of: tubular handling equipment operable to move drill pipe at the oil/gas wellsite; drill string make up and brake out equipment operable to connect and disconnect drill pipe; drill string hoisting equipment operable to move a drill string within a wellbore; and drill string rotation equipment operable to rotate the drill string within the wellbore.

The fluid control equipment may comprise at least one of: a choke manifold; a liquid gas separator; and a gas sensor.

The fluid control equipment and the data communication hub may be connected to a common frame, the fluid control equipment, the data communication hub, and the common frame may form at least a portion of an equipment skid movable as a single unit, and the method may further comprise, before operating the well construction system, transporting the equipment skid to the oil/gas wellsite.

The fluid control equipment may comprise a choke manifold and a liquid gas separator, and the liquid gas separator may be configured to receive fluid passing through the choke manifold.

The control workstation may comprise or be communicatively connected with a processor and a memory storing an executable computer program code.

The workstation may comprise a chair for a human wellsite operator, input devices disposed in association with the chairm, and a video output device disposed in association with the chair, and operating the control workstation may further comprise: entering control commands for controlling the fluid control equipment and the tubular handling and rotation equipment via the input devices by the human wellsite operator while sitting in the chair; and displaying information indicative of operational status of the fluid control equipment and the tubular handling and rotation equipment via the video output device.

Operation of the data communication hub may convert the received first information to the predetermined communication protocol.

The method may further comprise operating the well construction system to transmit the second information to the control workstation using the predetermined communication protocol.

The method may further comprise: operating the control workstation to transmit first control commands using the predetermined communication protocol to the data communication hub, and to transmit second control commands using the predetermined communication protocol to the tubular handling and rotation equipment; and operating the data communication hub to receive the first control commands using the predetermined communication protocol, and to transmit the first control commands using another communication protocol to the fluid control equipment. The first information may be generated by first sensors disposed in association with or forming at least a portion of the fluid control equipment, the second information may be generated by second sensors disposed in association with or forming at least a portion of the tubular handling and rotation equipment, the first control commands may be transmitted to first actuators disposed in association with or forming at least a portion of the fluid control equipment, and the second control commands may be transmitted to second actuators disposed in association with or forming at least a portion of the tubular handling and rotation equipment.

The method may further comprise communicatively connecting the control workstation, the tubular handling and rotation equipment, and the data communication hub with a rig control communication network to communicatively connect the control workstation with the tubular handling and rotation equipment and the data communication hub.

The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.

The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims. 

What is claimed is:
 1. An apparatus comprising: a data communication hub communicatively connected with fluid control equipment of a well construction system for constructing a well at an oil/gas wellsite; and a control workstation communicatively connected with tubular handling and rotation equipment of the well construction system, wherein the control workstation is communicatively connected with the data communication hub, and wherein the control workstation is communicatively connected with the fluid control equipment via the data communication hub.
 2. The apparatus of claim 1 wherein: the fluid control equipment comprises at least one of: a fluid processing system; a well control system; a managed pressure drilling control system; and a choke pressure control system; and the tubular handling and rotation equipment comprises at least one of: tubular handling equipment operable to move drill pipe at the oil/gas wellsite; drill string make up and brake out equipment operable to connect and disconnect drill pipe; drill string hoisting equipment operable to move a drill string within a wellbore; and drill string rotation equipment operable to rotate the drill string within the wellbore.
 3. The apparatus of claim 1 wherein the fluid control equipment comprises: a choke manifold; a liquid gas separator; and a gas sensor.
 4. The apparatus of claim 1 wherein the fluid control equipment and the data communication hub are connected to a common frame, and wherein the fluid control equipment, the data communication hub, and the common frame form at least a portion of an equipment skid movable as a single unit.
 5. The apparatus of claim 4 wherein the fluid control equipment comprises a choke manifold and a liquid gas separator, and wherein the liquid gas separator is configured to receive fluid passing through the choke manifold.
 6. The apparatus of claim 1 wherein the data communication hub comprises: a processing device; an actuator drive communicatively connected with the processing device and electrically connected with an electrical actuator disposed in association with or forming at least a portion of the fluid control equipment; and an electrical junction communicatively connected with the processing device and electrically connecting the data communication hub with a plurality of sensors disposed in association with or forming at least a portion of the fluid control equipment.
 7. The apparatus of claim 1 wherein the data communication hub is operable to: receive information from the fluid control equipment; and convert the information to a communication protocol signal for reception by the control workstation.
 8. The apparatus of claim 1 wherein: the data communication hub is operable to: receive first information using a first communication protocol from the fluid control equipment; and transmit the first information using a second communication protocol to the control workstation; and the control workstation is operable to: receive the first information using the second communication protocol from the data communication hub; and receive second information using the second communication protocol from the tubular handling and rotation equipment.
 9. The apparatus of claim 8 wherein: the control workstation is operable to: transmit first control commands using the second communication protocol to the data communication hub; and transmit second control commands using the second communication protocol to the tubular handling and rotation equipment; and the data communication hub is operable to: receive the first control commands using the second communication protocol; and transmit the first control commands using the first communication protocol to the fluid control equipment.
 10. The apparatus of claim 1 wherein the control workstation, the tubular handling and rotation equipment, and the data communication hub are communicatively connected with a rig control communication network to communicatively connect the control workstation with the tubular handling and rotation equipment and the data communication hub.
 11. An apparatus comprising: a control workstation for controlling a well construction system operable to construct a well at an oil/gas wellsite, wherein the control workstation is operable to: receive from fluid control equipment of the well construction system first information indicative of operational status of the fluid control equipment; and receive from tubular handling and rotation equipment of the well construction system second information indicative of operational status of the tubular handling and rotation equipment; and a data communication hub communicatively connected with the fluid control equipment via a plurality of first multi-conductor cables each connected with a corresponding piece of the fluid control equipment, wherein the data communication hub is communicatively connected with the control workstation via a second multi-conductor cable, and wherein the data communication hub is operable to: receive first information from the fluid control equipment via the plurality of first multi-conductor cables; and transmit the first information to the control workstation via the second multi-conductor cable.
 12. The apparatus of claim 11 wherein the fluid control equipment comprises at least one of: a choke manifold; a liquid gas separator; and a gas sensor.
 13. The apparatus of claim 11 wherein: the fluid control equipment and the data communication hub are connected to a common frame; the fluid control equipment, the data communication hub, and the common frame form at least a portion of an equipment skid movable as a single unit; the fluid control equipment comprises a choke manifold and a liquid gas separator; and the liquid gas separator is configured to receive fluid passing through the choke manifold.
 14. The apparatus of claim 11 wherein the data communication hub comprises: a processing device; an actuator drive communicatively connected with the processing device and electrically connected with an electrical actuator disposed in association with or forming at least a portion of the fluid control equipment; and an electrical junction communicatively connected with the processing device and electrically connecting the data communication hub with a plurality of sensors disposed in association with or forming at least a portion of the fluid control equipment.
 15. The apparatus of claim 11 wherein the second multi-conductor cable is a single multi-conductor cable, and wherein the data communication hub is operable to transmit the first information to the control workstation via the single multi-conductor cable.
 16. A method comprising: operating a well construction system to construct a well at an oil/gas wellsite while: generating first information indicative of operational status of fluid control equipment of the well construction system; and generating second information indicative of operational status of tubular handling and rotation equipment of the well construction system; operating a data communication hub to: receive the first information; and transmit the first information using a predetermined communication protocol; and operating a control workstation for controlling the well construction system to: receive the first information from the data communication hub; and receive the second information from the tubular handling and rotation equipment.
 17. The method of claim 16 wherein the fluid control equipment comprises at least one of: a choke manifold; a liquid gas separator; and a gas sensor.
 18. The method of claim 16 further comprising operating the data communication hub to convert the received first information to the predetermined communication protocol.
 19. The method of claim 16 further comprising operating the well construction system to transmit the second information to the control workstation using the predetermined communication protocol.
 20. The method of claim 16 further comprising: operating the control workstation to: transmit first control commands using the predetermined communication protocol to the data communication hub; and transmit second control commands using the predetermined communication protocol to the tubular handling and rotation equipment; and operating the data communication hub to: receive the first control commands using the predetermined communication protocol; and transmit the first control commands using another communication protocol to the fluid control equipment. 